TIDMENQ
RNS Number : 4630T
EnQuest PLC
25 March 2021
Results for the year ended 31 December 2020 and 2021 outlook
25 March 2021
Unless otherwise stated, all figures are on a Business
performance basis and are in US Dollars.
EnQuest Chief Executive, Amjad Bseisu, said:
"Our quick and decisive actions in early 2020, combined with our
reorganisation, have transformed the Company. We generated $211.1
million of free cash flow in the year, having significantly lowered
our cost base and free cash flow breakeven, enabling us to reduce
our debt to its lowest level since 2014. Capital and operating
expenditures reduced by $295.6 million and free cash flow
breakeven(1) for the year was $31.9/Boe, both in line with our
targets. Our focus on safety enabled us to minimise successfully
the impact of COVID-19 on our workforce and operations.
"The proposed acquisition of the low-cost Golden Eagle area will
strengthen our business, providing additional production and strong
cash flows which will partially utilise our UK tax assets.
"We successfully managed the unique set of challenges presented
in 2020, taking decisive action to protect and enhance our
business. Our focus on extending the useful lives of existing
assets through operational improvements and reducing emissions is
well suited to operating through the energy transition and I am
confident that EnQuest is well placed to succeed in a changing
world."
2020 performance
-- Group production averaged 59,116 Boepd in 2020, in line with guidance (2019: 68,606 Boepd)
-- Revenue of $856.9 million (2019: $1,711.8 million) and EBITDA of $550.6 million (2019: $1,006.5 million) reflect
lower year on year production and realised oil prices of $41.3/bbl, partially offset by lower operating costs
-- Cash generated from operations of $567.8 million (2019: $994.6 million); cash capital expenditure of $131.4
million (2019: $237.5 million)
-- Strong free cash flow generation of $211.1 million (2019: $368.5 million)
-- Cash and available bank facilities amounted to $284.1 million at 31 December 2020 (2019: $288.6 million), with
net debt reduced to $1,279.7 million (2019: $1,413.0 million)
-- Statutory reported basic loss after tax was $625.8 million reflecting non-cash impairments, including tax, of
$630.3 million, (2019: loss after tax of $449.3 million)
2021 performance and outlook(2)
-- Year to date February production averaged 46,635 Boepd, affected by outages, repairs and opportunistic
maintenance at Magnus and Kraken, which are now complete
-- Hedges in place for c.5 MMbbls of oil with an average floor price of c.$55/bbl and an average ceiling price of
c.$64/bbl
-- Full year average production expected to be between 46,000 to 52,000 Boepd, excluding Golden Eagle which will add
c.10,000 Boepd on a pro forma basis
-- Full year operating expenditure of c.$265 million
-- Combined cash capital and abandonment expenditure of c.$120 million3
(1) Based on the Group's aggregate cash outflows prior to any
debt repayments and $37.3 million of Magnus-related third-party gas
purchases divided by net working interest production
(2) Existing portfolio
(3) Excludes the costs associated with the PM8/Seligi riser
incident repair which are expected to be largely covered by
insurance
Production and financial information
2020 2019 Change
%
Production (Boepd) 59,116 68,606 (13.8)
------------------------------------------- ---------- ---------- --------
Revenue and other operating income
($m)(1) 856.9 1,711.8 (49.9)
------------------------------------------- ---------- ---------- --------
Statutory reported revenue and
other operating income ($m)(2) 865.6 1,646.5 (47.4)
------------------------------------------- ---------- ---------- --------
Realised oil price ($/bbl)(1,
3) 41.3 65.3 (36.8)
------------------------------------------- ---------- ---------- --------
Gross profit ($m) 71.4 468.3 (84.8)
------------------------------------------- ---------- ---------- --------
Statutory reported gross profit
($m) 66.6 402.5 (83.4)
------------------------------------------- ---------- ---------- --------
EBITDA ($m)(3) 550.6 1,006.5 (45.3)
------------------------------------------- ---------- ---------- --------
Profit/(loss) before tax and net
finance costs ($m) (20.0) 442.2 (104.5)
------------------------------------------- ---------- ---------- --------
Statutory reported (loss)/profit
after tax ($m) (625.8) (449.3) (39.3)
------------------------------------------- ---------- ---------- --------
Statutory reported basic (loss)/earnings
per share (cents) (37.8) (27.4) (38.0)
------------------------------------------- ---------- ---------- --------
Cash generated from operations
($m) 567.8 994.6 (42.9)
------------------------------------------- ---------- ---------- --------
Cash expenditures ($m) 173.0 248.6 (30.4)
------------------------------------------- ---------- ---------- --------
Capital(3) 131.4 237.5 (44.7)
------------------------------------------- ---------- ---------- --------
Abandonment 41.6 11.1 274.8
------------------------------------------- ---------- ---------- --------
End 2020 End 2019
------------------------------------------- ---------- ---------- --------
Net (debt)/cash ($m)(3) (1,279.7) (1,413.0) (9.4)
------------------------------------------- ---------- ---------- --------
Notes:
(1) Including realised losses of $6.1 million (2019: realised
gains of $24.8 million) associated with EnQuest's oil price
hedges
(2) Including net realised and unrealised gains of $2.7 million
(2019: net realised and unrealised losses of $40.6 million)
associated with EnQuest's oil price hedges
(3) See reconciliation of alternative performance measures
within the 'Glossary - Non-GAAP measures' starting on page 68
Production details
Average daily production 1 Jan 2020 1 Jan 2019
on a net working to to
interest basis 31 Dec 2020 31 Dec 2019
(Boepd)
-------------------------- ------------- -------------
(Boepd) (Boepd)
UK Upstream
- Magnus 17,416 18,267
- Kraken 26,450 25,172
- Other Upstream
(1) 6,468 5,644
------------- -------------
UK Upstream 50,334 49,083
UK Decommissioning
(2) 2,346 10,870
------------- -------------
Total UK 52,680 59,953
Total Malaysia 6,436 8,653
------------- -------------
Total EnQuest 59,116 68,606
------------- -------------
(1) Other Upstream: Scolty/Crathes, the Greater Kittiwake Area
and Alba
(2) UK Decommissioning: Heather/Broom, Thistle/Deveron, the Dons
and Alma/Galia
2020 performance summary
The Group's operational focus was to maintain strong production
efficiency across its asset base and successfully execute the
drilling programmes at Magnus and Kraken. The combined impact of
good operational delivery and the successful transformation of the
UK business enabled the Group to lower its unit operating expense
to $15.2/Boe, reduce its free cash flow breakeven to $31.9/Boe and
generate $211.1 million in free cash flow, enabling further
reductions in the Group's debt.
EnQuest's average production decreased by 13.8% to 59,116 Boepd,
in line with guidance, primarily reflecting a strong performance
from Kraken, offset by Thistle, Heather and Alma Galia moving to
cessation of production ('CoP') and the impact of the detached
riser at PM8/Seligi .
EBITDA and cash generated by operations were $550.6 million and
$567.8 million, respectively, with the reduction from 2019
reflecting lower prices and production, offset by lower operating
costs.
Cash capital expenditure of $131.4 million was focused on
executing the Group's drilling programmes at Kraken and Magnus.
Cash abandonment expenditure of $41.6 million reflected
decommissioning activities following CoP at Heather/Broom and
Alma/Galia.
Liquidity and net debt
At 31 December 2020, net debt was $1,279.7 million, down $133.3
million from $1,413.0 million at 31 December 2019, reflecting a
strong operational performance and cash generation. Total cash and
available facilities were $284.1 million, including ring-fenced
funds held in operational accounts associated with Magnus, the
Sculptor Capital facility and other joint venture accounts
totalling $108.0 million.
The Group's material free cash flow generation enabled early
voluntary repayments of the senior credit facility, which reduced
by $97.8 million during the year. This reduction included the $65.0
million associated with the April 2021 scheduled amortisation.
Following a further voluntary early repayment of $25.0 million in
January 2021, the senior credit facility, including payment in kind
interest, totalled $352.3 million at the end of February.
The senior credit facility expires in October 2021. Securing
lenders commitment to a new senior secured facility in conjunction
with the Golden Eagle acquisition remains on track and the
Directors are confident of a successful outcome. Further details on
the status of refinancing are provided in the going concern
disclosure on page 15.
Reserves and resources
Net 2P reserves at the end of 2020 were 189 MMboe (2019: 213
MMboe) and have been audited on a consistent basis with prior
years. During the year, the Group produced 10.1% of its year-end
2019 2P reserves base, with other revisions primarily reflecting
the CoP decisions at Thistle/Deveron and the Dons, largely offset
by other 2P reserves revisions and transfers from 2C resources at
Kraken, Magnus and PM8/Seligi. Net 2C resources are 279 MMboe
(2019: 173 MMboe), an increase of 61.3% compared to the end of 2019
primarily as a result of the agreement to acquire 40.81% equity and
operatorship of the Bressay field in the UK in July 2020 which
added 115 MMboe.
Environmental, Social and Governance performance
The Group's absolute Scope 1 and 2 emissions were 11.2% lower in
2020 compared to 2019 and 25.5% lower than 2018, primarily
reflecting the Group's decisions to cease production at its
Heather, Thistle/Deveron and Alma/Galia assets. The Group has set
itself a challenging target to deliver a further reduction in Scope
1 and 2 emissions of c.10% over the next three years from its
existing portfolio through the identification and implementation of
economic emission reduction opportunities, with the achievement of
this target linked to reward. The Group continues to optimise sales
of Kraken cargoes directly into the shipping fuel market, avoiding
emissions related to refining and helping reduce sulphur emissions
in accordance with the IMO 2020 regulations. The avoidance of
emissions related to Kraken's crude is significant, with refining
emissions for a typical North Sea crude estimated to be c.32 -
36kgCO2e/bbl(1, 2) . As such, emissions relating to Kraken oil by
the time it reaches its end user, compares favourably on a
fully-refined basis to even high-performing North Sea fields(3)
.
The Group's strong safety culture was clearly evidenced as the
Company successfully implemented a number of mitigations to
minimise the impact of COVID-19 on its people and operations. The
Group also achieved a significant reduction in its lost time
incident frequency rate of 0.22, materially below the UKCS
benchmark of 1.28. However, the Group experienced asset integrity
issues with a detached riser in Malaysia and pipeline issues at
SVT. EnQuest is committed to continuous improvement in asset
integrity and continues to ensure that the Group's integrity
management systems appropriately identify focus areas.
To reflect the Board's commitment to ESG matters, the remits of
the current Board-level committees were strengthened to ensure the
Group's ESG performance is aligned with EnQuest's purpose and
appropriately responds to the expectations of our stakeholders. The
composition of the Committees was also reviewed to ensure they
remained efficient and effective, with some alterations to certain
Committee memberships. There were also a number of Board changes
during the year and in early 2021, revising the balance of skills,
expertise and experience of the Board and improving its gender and
ethnic diversity.
(1) kgCO2e/bbl = kilograms of CO(2) equivalent per produced
barrel
(2) Based on an the University of Calgary PRELIM model
recognised by California Air Resources Board, US Energy Tech.
Laboratory, USDOE Office of Energy Efficiency and Renewable Energy,
Carnegie Endowment for International Peace and the US Environmental
Protection Agency
(3) EnQuest analysis of UK North Sea assets 2019 performance
2021 performance and outlook details
In February, EnQuest signed an agreement to purchase Suncor's
entire 26.69% non-operated equity interest in the Golden Eagle
area, comprising the producing Golden Eagle, Peregrine and
Solitaire fields for an initial consideration of $325 million. Upon
completion, the acquisition will add immediate material low-cost
production and cash flow to EnQuest and will allow the Group to
accelerate the use of its tax losses. The four well infill
programme is continuing, with the first three wells safely
completed and online.
Production performance to the end of February has been slightly
behind schedule. An unplanned third-party outage, power related
failures and ongoing well repair activities at Magnus, along with a
short duration shutdown at Kraken for a riser tether repair have
been partially offset by PM8/Seligi wells coming back online ahead
of schedule. Repairs are now complete on the Kraken tether and
Magnus power systems. In addition, a successful Magnus well
intervention and early commissioning of gas lift at Kittiwake have
further increased production from the end of February.
For the full year, the Group's net production is expected to be
between 46,000 and 52,000 Boepd (excluding any contribution from
the proposed Golden Eagle transaction). This guidance includes CoP
at the Dons fields which occurred as planned in the first quarter,
continued low production at PM8/Seligi until repairs on the riser
are completed during the second half of the year and natural
declines across the portfolio. Kraken gross production is expected
to be between 30,000 and 35,000 Bopd (21,150 and 24,675 Bopd net),
reflecting natural declines.
The Group continues to focus on cost control and capital
discipline, with operating expenditures expected to be
approximately $265 million and combined cash capital and
abandonment expenditure expected to be around $120 million, which
are lower than 2020. Capital expenditure primarily relates to
license to operate activities and guidance excludes the costs
associated with the PM8/Seligi riser incident repair which are
expected to be largely covered by insurance, while abandonment
expense primarily reflects decommissioning programmes at
Heather/Broom, including an acceleration of some work scopes, the
Thistle/Deveron fields and the Dons.
EnQuest has hedged a total c.5 MMbbls for 2021 using costless
collars, with an average floor price of c.$55/bbl and an average
ceiling price of c.$64/bbl.
COVID-19 update
The health, safety and wellbeing of EnQuest's employees is the
top priority. The Group remains compliant with UK, Malaysia and
Dubai government and industry policy. The Group has also been
working with a variety of stakeholders, including industry and
medical organisations, to ensure its operational response and
advice to its workforce is appropriate and commensurate with the
prevailing expert advice and level of risk. The Group's day-to-day
operations continue without being materially affected by
COVID-19.
Summary financial review of 2020
(all figures quoted are in US Dollars and relate to Business
performance unless otherwise stated)
2020 was an extremely challenging year with the oil price
collapse of March 2020, the COVID-19 pandemic and the resulting
impacts on the macro-economic environment. As a result, the company
went through significant changes, including decisions to cease
production at some assets and transform the organisation with a
focus on cost and capital expenditure reductions. Notwithstanding
the very challenging environment, the Group delivered on its 2020
production and cost guidance. The early and decisive action to
reduce costs resulted in operating and capital expenditures being
$295.6 million lower than 2019, materially lowering the Group's
free cash flow breakeven.
Revenue for 2020 was $856.9 million, 49.9% lower than in 2019
($1,711.8 million), reflecting the materially lower oil prices, a
reduction in production following the decision to cease production
at Heather, Thistle and Alma/Galia and moving from a net overlift
to a net underlift position. Revenue is predominantly derived from
crude oil sales which totalled $779.9 million, 49.6% lower than in
2019 ($1,548.2 million). Revenue from the sale of condensate and
gas was $60.5 million (2019: $120.2 million), reflecting
significantly lower market prices for gas in relation to the onward
sale of third-party gas purchases not required for injection
activities at Magnus.
The Group's commodity hedge programme resulted in realised
losses of $6.1 million in 2020 (2019: gains of $24.8 million). The
Group's average realised oil price excluding the impact of hedging
was $41.6/bbl, compared to $64.2/bbl for 2019. The Group's average
realised oil price including the impact of hedging was $41.3/bbl in
2020, 36.8% lower than in 2019 ($65.3/bbl).
Total cost of sales were $785.5 million for the year ended 31
December 2020, 36.8% lower than in 2019 ($1,243.6 million).
The Group's operating expenditures of $328.6 million were 36.6%
lower than in 2019 ($518.1 million), primarily reflecting the
Group's focus on cost control, including the decision to cease
production at Heather, Thistle and Alma Galia. Unit operating costs
decreased by 26.2% to $15.2/Boe (2019: $20.6/Boe).
Total cost of sales also included non-cash depletion expense of
$438.2 million, 16.5% lower than in 2019 ($525.1 million), mainly
reflecting the decision to cease production at Heather, Thistle and
Alma/Galia and a decrease in the unit-of-production rate arising
from impairments booked in the first half of the year.
The credit relating to the Group's lifting position and
inventory was $34.8 million (2019: $102.9 million). This reflects a
switch to a $3.0 million net underlift position at 31 December 2020
from a $28.6 million net overlift position at 31 December 2019.
Other cost of operations of $53.4 million were 45.1% lower than
in 2019 ($97.5 million), reflecting the lower cost of
Magnus-related third-party gas purchases following the reduction in
the market price for gas, partially offset by a $24.9 million
inventory write down recognised in the year, which primarily
relates to inventory held at assets now scheduled for
decommissioning.
EBITDA for 2020 was $550.6 million, down 45.3% compared to 2019
($1,006.5 million). This was driven by lower revenue, partially
offset by lower cost of sales.
The tax credit for 2020 of $172.5 million (2019: $23.6 million
tax charge), excluding exceptional items, is mainly due to the Ring
Fence Expenditure Supplement on UK activities generated in the
year. UK North Sea corporate tax losses at the end of the year
increased to $3, 183.9 million (2019: $2,903.4 million), primarily
as a result of the Ring Fence Expenditure Supplement generated in
the year .
Remeasurement and exceptional items for 2020 were a net post-tax
loss of $599.6 million (2019: loss of $663.6 million). Revenue
included unrealised gains of $8.8 million in respect of the
mark-to-market movement on the Group's commodity contracts (2019:
unrealised losses of $65.4 million). Other remeasurement and
exceptional items includes a $138.2 million gain in relation to the
fair value recalculation of the Magnus contingent consideration
reflecting the reduction in oil price assumptions. The Group also
recognised post-tax non-cash impairment charges on its oil and gas
assets of $259.2 million (2019: $397.5 million), reflecting a
reduction in oil price assumptions, and a non-cash de-recognition
of undiscounted deferred tax assets of $371.1 million.
The Group's reported cash generated from operations for 2020 was
$567.8 million (2019: $994.6 million), primarily as a result of
lower revenue. Free cash flow for 2020 was $211.1 million (2019:
$368.5 million).
Net debt at 31 December 2020 was $1,279.7 million, a decrease of
9.4% compared to 2019 ($1,413.0 million). This includes $205.8
million of payment in kind interest ("PIK interest") that has been
capitalised to the principal of the facility and bonds pursuant to
the terms of the Group's November 2016 refinancing (31 December
2019: $133.3 million).
In January 2021, EnQuest made an early voluntary repayment of
$25.0 million of the senior credit facility. The final payment of
$352.3 million, including $17.3 million PIK interest, is due on 1
October 2021.The Group is currently in the process of refinancing
the facility in conjunction with the Golden Eagle acquisition.
In June 2020, EnQuest made an early voluntary repayment of the
entire $31.7 million of the Tanjong Baram Project Finance facility
having received the first of three instalments from Petronas for
reimbursement of outstanding net capital expenditure of $51.1
million relating to the Tanjong Baram project. The remaining two
reimbursement instalments were received in the second half of the
year.
The strong production performance at Kraken has driven a $55.2
million reduction in the Sculptor Capital facility in the year.
Ends
For further information please contact:
EnQuest PLC Tel: +44 (0)20 7925
4900
Amjad Bseisu (Chief Executive)
Jonathan Swinney (Chief Financial Officer)
Ian Wood (Head of Communications & Investor
Relations)
Jonathan Edwards (Senior Investor Relations
& Communications Manager)
Tulchan Communications Tel: +44 (0)20 7353
4200
Martin Robinson
Martin Pengelley
Harry Cameron
Presentation to Analysts and Investors
A presentation to analysts and investors will be held at 09:00
today - London time. The presentation will be accessible via an
audio webcast, available on the investor relations section of the
EnQuest website at www.enquest.com . A conference call facility
will also be available at 09:00 on the following numbers:
Conference call details:
UK : +44 (0) 800 279 6619
International: +44 (0) 207 192 8338
Confirmation Code: 8538947
Notes to editors
This announcement has been determined to contain inside
information. The person responsible for the release of this
announcement is Stefan Ricketts, General Counsel and Company
Secretary.
ENQUEST
EnQuest is providing creative solutions through the energy
transition. As an independent production and development company
with operations in the UK North Sea and Malaysia, the Group's
strategic vision is to be the operator of choice for maturing and
underdeveloped hydrocarbon assets by focusing on operational
excellence, differential capability, value enhancement and
financial discipline.
EnQuest PLC trades on both the London Stock Exchange and the
NASDAQ OMX Stockholm.
Please visit our website www.enquest.com for more information on
our global operations.
Forward-looking statements: This announcement may contain
certain forward-looking statements with respect to EnQuest's
expectations and plans, strategy, management's objectives, future
performance, production, reserves, costs, revenues and other trend
information. These statements and forecasts involve risk and
uncertainty because they relate to events and depend upon
circumstances that may occur in the future. There are a number of
factors which could cause actual results or developments to differ
materially from those expressed or implied by these forward-looking
statements and forecasts. The statements have been made with
reference to forecast price changes, economic conditions and the
current regulatory environment. Nothing in this announcement should
be construed as a profit forecast. Past share performance cannot be
relied upon as a guide to future performance.
Chief Executive's report
Overview
2020 presented the Group with a unique set of challenges through
the combination of the oil price collapse of March 2020, the
COVID-19 pandemic and the resulting crash in the global financial
markets, which we have managed successfully. As always, the safety
of EnQuest's people and assets remained an absolute priority. The
Group minimised successfully the impact of COVID-19 on its
workforce and operations, by supplementing its existing
communicable disease processes and introducing a number of new
protocols in both the pre-mobilisation and onsite management
processes. The difficult but decisive action taken in response to
the macroeconomic environment saw the cessation of production at a
number of the Group's assets, a reduction in the number of employee
and contractor roles in the UK and the reorganisation of the UK
North Sea business into three directorates: UK Upstream; UK
Midstream; and UK Decommissioning. These actions have transformed
the business, materially lowering the Group's cost base and
enabling the directorates to focus on the most appropriate
activities that deliver operational excellence and SAFE Results at
each of their assets.
As we transformed our business and lowered our cost base, we
have maintained our focus on health and safety, recognising this is
our licence to operate. Given the riser incident in Malaysia, we
have also initiated a Company-wide asset integrity review and are
developing fit-for-purpose safety systems for late life assets.
As an established oil and gas company, EnQuest has always aimed
to safely improve the operating, financial and environmental
performance of assets for the benefit of its stakeholders. However,
over the last few years, and in 2020 in particular, Environmental,
Social and Governance ('ESG') factors have continued to grow in
importance for companies. As such, the Group undertook a review of
the ESG landscape in order to identify those ESG factors which are
relevant and applicable to its business model, to ensure its
approach was appropriate and easily understood by its
stakeholders.
Throughout the year, the Group's operational focus was to
maintain strong production efficiency across its asset base and
successfully execute the drilling programmes at Magnus and Kraken.
The combined impact of good operational delivery and the successful
transformation of the UK business enabled the Group to lower its
unit operating expense to c.$15.2/Boe, reduce its free cash flow
breakeven(1) to c.$31.9/Boe and generate $211.1 million in free
cash flow, enabling further reductions in the Group's debt.
(1) Based on the Group's aggregate cash outflows prior to any
debt repayments and $37.3 million of Magnus-related third-party gas
purchases divided by net working interest production
Operational performance
EnQuest's average production decreased by 13.8% to 59,116 Boepd,
slightly below the mid-point of the Group's guidance. The decrease
was primarily driven by the Group's decision to cease production at
its highest cost assets: Heather/Broom; Thistle/Deveron; and
Alma/Galia, and the impact of the detached riser in Malaysia.
Kraken continued to perform well, delivering high production
efficiency of 87% and gross production of 37,518 Bopd, above the
top end of its guidance range. Overall subsurface and well
performance was good and production optimisation activities
continued through improved injector-producer well management. By
the end of 2020, more than 40 MMbbls (gross) had been produced
since first oil, a great achievement by the combined EnQuest and
Bumi Armada team. Production at Magnus also remained robust,
delivering 17,416 Boepd reflecting the contribution of the two new
wells coming onstream in March, partially offset by gas compressor
and seawater lift pump system availability. Production at
PM8/Seligi was lower than the prior year reflecting the impact of a
detached riser at the Seligi Alpha platform which provides gas lift
and injection to the Seligi Bravo platform. This resulted in a
release of gas which initiated an automatic emergency shutdown of
the PM8/Seligi field. The Group's safety systems and emergency
response procedures were successfully implemented, with all
personnel onboard mustered safely within minutes. Following an
initial
investigation and safety assessment, partial operations were
able to be recommenced within two days, although production
remained low throughout the fourth quarter.
At Heather and Thistle/Deveron, cessation of production ('CoP')
applications were approved, with decommissioning activities
commencing in preparation of the well abandonment programmes
planned for 2021. At Alma/Galia, CoP occurred on 30 June 2020 as
planned, with the EnQuest Producer floating production, storage and
offloading vessel moving off station shortly thereafter and
transferred to the oil terminal jetty at Nigg.
During the year, the Group produced 10.1% of its year-end 2019
2P reserves base, which overall reduced to 189 MMboe at the end of
2020, down 11.3% on the 213 MMboe at the end of 2019. Following the
agreement to acquire 40.81% equity and operatorship of the Bressay
field in the UK, the Group's 2C resources increased by 61.3% from
the end of 2019 to around 279 MMboe. Other material 2C resources
are located at Magnus and Kraken in the UK and PM8/Seligi and
PM409, offshore Malaysia. In February, the Group agreed to acquire
Suncor's entire 26.69% non-operating interest in the Golden Eagle
area. Upon completion, expected before the end of the third quarter
2021, this is expected to add around 23 MMbbls to reserves and
resources.
Financial performance
The Group's EBITDA decreased by 45.3% to $550.6 million,
reflecting the material decrease in realised oil and gas prices and
lower production, partially offset by the Group's transformation
and ongoing focus on cost control, which drove operating
expenditure down by $189.5 million to $328.6 million, with unit
operating costs reduced to around $15.2/Boe. Cash generated by
operations decreased to $567.8 million, down 42.9% compared to
2019, with free cash flow generation of $211.1 million.
This strong cash flow performance in difficult macroeconomic
conditions facilitated a material reduction in the Group's net
debt, which ended the year at $1,279.7 million, down $133.3 million
from the end of 2019. Voluntary early repayments of the Group's
senior credit facility, including a further $25.0 million in
January 2021, has seen the outstanding balance reduce to $352.3
million (including Payment in Kind) with no further amortisations
due ahead of the final maturity in October 2021. The strong
performance at Kraken has also driven a $55.2 million reduction in
the Sculptor Capital facility.
At the year end, the Group recognised non-cash post-tax
impairments of $259.2 million, mainly reflecting lower oil price
assumptions and non-cash de-recognition of undiscounted deferred
tax assets of $3671.1 million.
Environmental, Social and Governance
Environmental
Emissions performance is an area of great importance to EnQuest
as a responsible operator of oil and gas assets through the
multi-decade energy transition, aiming to extend production lives
safely, enhance cash flow profiles and reduce costs and emissions
on mature assets, as society's reliance on hydrocarbons is reduced,
thereby contributing towards the achievement of national emissions
targets. The Group's absolute Scope 1 and 2 emissions were 11.2%
lower in 2020 compared to 2019, primarily reflecting the Group's
decisions to cease production at its Heather/Broom, Thistle/Deveron
and Alma/Galia assets. The Group has also set itself a challenging
target to deliver a further reduction in Scope 1 and 2 emissions of
c.10% over the next three years from its existing portfolio through
the identification and implementation of economic emission
reduction opportunities, with the achievement of this target linked
to reward. Emission reduction is also part of the acquisition
review process, with a carbon price built into economic evaluation.
The Group continues to optimise sales of Kraken cargoes directly to
the shipping fuel market, avoiding emissions related to refining
and helping reduce sulphur emissions in accordance with the IMO
2020 regulations.
Social - Health and safety
EnQuest's absolute priority has consistently been SAFE Results,
no harm to our people and respect for the environment. During 2020,
an independent review of the safety culture provided positive
feedback on the strong commitment to safety throughout EnQuest,
with well-motivated and informed people supported by robust
processes. This culture was clearly evidenced as the Company
successfully implemented a number of mitigations to minimise the
impact of COVID-19 on its people and operations. Despite the
necessary disruption caused by the Group's enhanced procedures and
protocols, the Group achieved: a Lost Time Incident frequency rate
of just 0.22, 61% lower than 2019 and well below the UK Continental
Shelf benchmark of 1.28; a 79% reduction in safety-critical repair
orders; and a reduction in reportable hydrocarbon releases.
However, challenges were experienced with pipeline integrity at the
Sullom Voe Terminal in the UK and the detached riser on PM8/Seligi
in Malaysia. EnQuest is committed to continuous improvement in
asset integrity and, with the support of third parties to give an
independent viewpoint, there is an ongoing review to identify
strengths and opportunities in the Group's integrity management
system.
Alongside the ongoing focus on physical safety, the Group
offered additional support that focused on the welfare of its
employees' mental health and wellbeing throughout the year,
recognising the impact the global pandemic and the business
transformation had on EnQuest's people. The workforce was provided
with access to a number of services and a wide variety of
challenges, competitions and communications to help keep people
connected.
Social - People
The Group remains committed to improving workforce diversity and
inclusion ('D&I'), and there was a renewed examination of the
Company's approach during this period of intense change. A
Company-wide D&I strategy, aligned to its updated D&I
policy, was developed aimed at building awareness by providing
education and understanding throughout the workforce. EnQuest also
continued to support International Women in Engineering Day and the
UK's AXIS Network. During 2021, enhanced diversity balance will
continue to be a core driver of the Group's recruitment, employment
and training policies and how it attracts, retains and develops a
wide range of talent in the organisation. At present, 19% of
EnQuest's leadership teams are female and 43% are from diverse
ethnic backgrounds. The Group is committed to improving diversity
further and an employee-led global community was established to
explore and promote a greater sense of connectedness and
celebration of difference at EnQuest. The 'EnQlusion' committee has
already hosted a talk from the Association for Black and Minority
Ethnic Engineers and continue to work on ways to develop a more
diverse and inclusive workplace.
Social - Communities
EnQuest has also continued to provide support to the communities
in which it works. In Malaysia, EnQuest is sponsoring two
university students to study STEM-related subjects at University
Malaya and Universiti Teknologi Malaysia and has also signed a
Memorandum of Agreement to sponsor the 'IChemE' accreditation of
the Chemical Engineering programme at The National University of
Malaysia. The Group continues to provide financial support to a
local school and other charitable organisations. In the UK, local
community support included financial contributions to charitable
organisations throughout the year, with donations of excess
personal protective equipment from offshore to Shetland NHS and a
local care home in Aberdeen and the redeployment of frozen meals to
an Aberdeenshire food bank during the COVID-19 pandemic.
2021 performance and outlook
In February, EnQuest signed an agreement to purchase Suncor's
entire 26.69% non-operated equity interest in the Golden Eagle
area, comprising the producing Golden Eagle, Peregrine and
Solitaire fields for an initial consideration of $325 million. Upon
completion, the acquisition will add immediate material low-cost
production and cash flow to EnQuest and will allow the Group to
accelerate the use of its tax losses. EnQuest plans to finance the
transaction through a combination of a new secured debt facility,
interim period post-tax cash flows between the economic effective
date of 1 January 2021 and completion, and an equity raise. It is
anticipated the new secured debt facility will incorporate the
refinancing of the existing outstanding senior credit facility.
Production performance to the end of February has been towards
the lower end of the guidance range. An unplanned third-party
outage, power-related failures and ongoing well repair activities
at Magnus, along with short duration shutdowns at Kraken for tether
inspections and repairs, have been partially offset by PM8/Seligi
wells coming back online ahead of schedule. Repairs are now
complete on the Kraken tethers and Magnus power systems. In
addition, a successful Magnus well intervention and early
commissioning of gas lift at Kittiwake have further increased
production from the end of February.
For the full year, the Group's net production is expected to be
between 46,000 and 52,000 Boepd (excluding any contribution from
the proposed Golden Eagle transaction) and includes the cessation
of production at the Dons which occurred as planned in the first
quarter, continued low production at PM8/Seligi until repairs on
the riser are completed during the second half of the year and
natural declines across the portfolio. Kraken gross production is
expected to be between 30,000 and 35,000 Bopd (21,150 and 24,675
Bopd net), reflecting natural declines.
The Group continues to focus on cost control and capital
discipline, with operating expenditures expected to be
approximately $265 million and combined cash capital and
abandonment expenditure is expected to be around $120 million, all
of which are lower than 2020. Capital expenditure primarily relates
to licence to operate activities and abandonment expense primarily
reflects decommissioning programmes at Heather/Broom, including an
acceleration of some work scopes, the Thistle/Deveron fields and
the Dons.
Longer-term development
EnQuest has been transformed in 2020 with a focused portfolio
and a materially lower cost base. At the end of 2020, the Group had
c.279 MMbbls of net 2C resources, primarily located at Bressay,
Magnus and Kraken in the UK and PM8/Seligi and PM409 in Malaysia.
The completion of the Bressay acquisition provides EnQuest with a
further opportunity to demonstrate its proven capabilities in
low-cost drilling, near-field and heavy oil development. The
low-cost Golden Eagle field will provide incremental production,
reserves and resources, with a number of unsanctioned activities
associated with further sub-sea and platform infill drilling,
topsides water debottlenecking and an active well intervention
programme being assessed. With a focus on short-cycle projects,
EnQuest is able to adjust its capital allocation decisions to match
the prevailing oil demand and price environment, balancing debt
reduction, the development of its existing portfolio, the
acquisition of suitable growth opportunities and returns to
shareholders.
EnQuest successfully managed the unique set of challenges
presented in 2020, taking decisive action to protect and enhance
the business. The focus on extending the useful lives of existing
assets through operational improvements and reducing emissions is
well suited to operating through the energy transition, meaning
EnQuest is well placed to succeed in a changing world.
Operating review
UK Upstream operations
2020 performance summary
Production of 50,334 Boepd was 2.5% higher than in 2019,
reflecting strong performances at Kraken and Scolty/Crathes,
partially offset by lower than expected performance at Magnus and
natural declines across the Upstream portfolio.
Magnus
2020 performance summary
Production of 17,416 Boepd was 4.7% lower than in 2019.
Performance was impacted by gas compressor and seawater lift pump
availability and natural declines. Offsetting this was the
contribution from two new wells, which came onstream in the first
quarter combined with good production and water injection
efficiency, both of which averaged c.80%.
During the year, the Group continued to focus on activities to
improve production, including well interventions, reservoir
management and gas compression optimisation, in addition to
successfully completing a planned maintenance shutdown in
October.
2021 performance and outlook
Average production in the first two months of 2021 was 13,770
Boepd, impacted by an unplanned third-party outage and power
failures, which have now been resolved.
Looking ahead, shutdowns with a duration equivalent of around
two weeks are planned over the summer to undertake essential
maintenance work, while further production enhancement activities
will continue to be assessed and implemented throughout the
year.
Preparatory works will be undertaken in 2021 ahead of the
planned development drilling programme in 2022. In addition,
following the award of block 211/12b as part of the 32nd licensing
round, the Group will commence subsurface studies to assess the
block for future opportunities. With 2C resources of c,35 MMboe,
Magnus offers the Group significant low-cost drilling opportunities
in the medium term, in addition to an estimated c.250 MMbbls of
remaining mobile oil in place that requires further evaluation to
identify future drilling and tie-back prospects.
Kraken
2020 performance summary
Average gross production was 37,518 Bopd, 5.1% higher than in
2019 and ahead of the top end of the Group's 2020 guidance range of
30,000 to 35,000 Bopd (gross) (21,150 and 24,675 Bopd net).
Production efficiency of 87% and water injection efficiency of 91%
remained strong with the FPSO vessel performing well throughout the
year. During the third quarter, the Group successfully completed
the planned shutdown to undertake essential maintenance work,
although unplanned repairs were required to the DC1 riser in the
fourth quarter which resulted in two producer wells being shut in
for approximately two weeks.
Overall subsurface and well performance has been good, with
water cut evolution remaining stable. The Group has continued to
focus on optimising production through improved producer-injector
well management, incorporating the results of regular well testing
programmes. In addition, drilling at Worcester was concluded in the
first half of the year with a new producer-injector pair coming
onstream late in the second quarter.
Since the delivery of first oil in June 2017, gross output has
significantly increased from 7.7 MMbbls in the first 12 months of
operation to over 13.7 MMbbls for the full year 2020. This equates
to over 40 million barrels produced since inception.
Due to its low sulphur content, the Group is able to optimise
Kraken cargo sales into the shipping fuel market with Kraken oil a
key component of IMO 2020 compliant low-sulphur fuel oil. As such,
the Group benefits from strong pricing in the market and avoids
refining-related emissions.
2021 performance and outlook
Average gross production of 33,723 Bopd for the first two months
of 2021 is in line with guidance and cargoes have continued to be
sold at a premium to Brent.
A very short shutdown was undertaken during the first quarter to
complete a riser tether repair, while over the summer, a further
short shutdown is being reviewed to undertake essential maintenance
work.
The Group is not currently planning to return to drilling until
2023. However, the Group plans to carry out a 3D seismic campaign
in the second half of 2021 to support ongoing evaluation work to
identify and prioritise near-field drilling and sub-sea tie-back
opportunities within the Pembroke, Antrim and Maureen sands
discoveries and prospects in the western area, which holds an
estimated 70-130 MMbbls of STOIIP.
The Group expects Kraken production to be between 30,000 Bopd
and 35,000 Bopd (21,250 and 24,675 Bopd net) in 2021.
Other Upstream assets
2020 performance summary
Production of 6,468 Boepd was 14.6% higher than in 2019, driven
by a strong performance at Scolty/Crathes following the completion
of the pipeline replacement project in the third quarter of 2019.
Both the Scolty and Crathes wells have been performing well, with
optimisation activities continuing to partly mitigate expected
natural declines. This strong performance was partially offset by
lower production elsewhere in the Greater Kittiwake Area ('GKA'),
primarily as a result of a failure of an umbilical providing power
to the Mallard and Gadwall wells impacting production, along with
underlying natural declines.
Given the COVID-19 pandemic, the four-week Forties Pipeline
System ('FPS') planned shutdown was deferred to 2021. Instead, a
short planned shutdown was completed in the third quarter to
undertake essential maintenance work.
At Alba, performance continued in line with the Group's
expectations.
2021 performance and outlook
Aggregate production to the end of February was 3,821 Boepd.
At Scolty/Crathes, gas lift was introduced late in the first
quarter to support production, while at GKA, a return to normal
production levels is expected during the second half of the year,
following the reinstatement of power to the Mallard and Gadwell
wells. A planned four-week shutdown is expected to be undertaken
during the second quarter, in line with the Forties Pipeline System
shutdown deferred from 2020.
In January, the Group announced the Bressay transaction had been
successfully completed. This acquisition provides the Group with
the opportunity to develop around 115 MMbbls (net) 2C resources,
offering a long-term, low-risk production opportunity that has
similarities to the Group's Kraken field. Under the agreement,
EnQuest has assumed operatorship of the licences with a
participating interest of 40.81% for an initial consideration of
GBP2.2 million, payable as a carry against 50% of Equinor's net
share of costs from the point EnQuest assumed operatorship. During
2021, detailed analysis of existing reservoir data and an
assessment of potential development options will be undertaken.
UK Midstream operations
2020 performance summary
The Group's delivery infrastructure in the UK North Sea is, to a
significant extent, dependent on the SVT and its associated
pipelines. With safe and reliable performance continuing at SVT,
the Group has been able to maintain 100% service availability at
the terminal.
During the second quarter, a major milestone was achieved in
bringing Jetty 3 back into operation after almost seven years, with
safe operations maintained throughout project delivery. The
re-introduction of operations at the jetty provides the Group with
additional capacity which helps to ensure greater service
availability for customers. Following this increased capacity, the
Group was pleased to welcome the Very Large Crude Carrier ('VLCC')
"Front Endurance" to the terminal to load a cargo of c.1.8 MMbbls
of Brent oil, the first VLCC to visit SVT since 2010.
Since taking over operatorship at SVT, the Group has worked in
close collaboration with all its stakeholders to optimise safely
and sustainably the size and scale of plant required to ensure the
terminal continues to meet existing and future customer needs. This
focus has driven base operating expenditure reductions of around
one-third, through progressively reducing the physical
infrastructure in place, with the efficiency programme continuing
to progress in line with expectations.
In pipelines, good progress has been made undertaking planned
repairs and remediation work on delivery infrastructure to ensure
continued smooth operations. The Group also successfully completed
planned shutdowns on the Ninian Pipeline System and connected
sub-sea network.
2021 performance and outlook
It has been a good start to the year, with stable operations and
plant availability continuing at SVT and the associated pipeline
infrastructure.
In March, the Group was pleased to receive confirmation that
negotiations with BP for the long-term export solution for the
Clair Development would continue.
During 2021, planned maintenance is scheduled to be undertaken
on Jetty 2 which, once completed, will improve the service offering
to customers. The Group also expects to undertake a number of
planned maintenance inspections on the Northern Leg Gas
pipeline.
The Group is continuing to evaluate its options at SVT to
optimise and accelerate its drive to deliver further efficiencies,
including emissions reductions. EnQuest is focused on maintaining
safe and reliable operations at the terminal while transforming its
operations to ensure it has the right service footprint in place to
deliver a competitive, cost-effective and reliable service to
existing and future users.
The strategic importance and geographical positioning of SVT has
enabled EnQuest to participate in Project Orion, an initiative
being developed by the Shetland Islands Council and the Oil and Gas
Technology Centre aiming to deliver a clean, sustainable energy
future for Shetland and the UK.
UK Decommissioning
2020 performance summary
Average production of 2,346 Boepd was 78.4% lower than in 2019,
primarily reflecting the decisions to cease production at the
Heather/Broom and Thistle/Deveron fields, which during 2019
contributed c.6,000 Boepd. At the Dons, production was impacted by
a lack of gas lift which was no longer available from Thistle,
combined with underlying natural declines. As such, preparations
commenced for the field to cease production during the first
quarter of 2021. As planned, Alma/Galia ceased production in June
2020, with the EnQuest Producer FPSO moving off station in
September and sailing to the oil terminal jetty at Nigg, where the
Group continues to evaluate options for its future.
The cessation of production ('CoP') application at Heather was
accepted by the regulator in June, reducing EnQuest's share of
costs from 100% to 37.5% and allowing decommissioning to commence.
The platform remained shut in and depressurised all year, with
front end engineering activities being undertaken ahead of the
resumption of the well abandonment programme in 2021. At Broom the
application for CoP has been submitted to the regulators and
approval is expected shortly.
At the Thistle platform, project activities related to the
successful removal of the redundant crude oil storage tanks were
concluded over the summer. In June, the CoP application for
Thistle/Deveron was accepted, resulting in EnQuest's share of
post-tax costs reducing from 99% to 6.1% and allowing for the
decommissioning phase to begin. The facility remained unmanned all
year, although preservation visits to the Thistle platform took
place as part of the preparatory works ahead of the planned 2021
well abandonment programme.
2021 performance and outlook
As expected, the Dons ceased production in early 2021 following
the receipt of necessary partner and regulatory approvals in
respect of CoP. The Northern Producer floating production facility
is being used for initial decommissioning activities, such as
flushing of the sub-sea infrastructure and to support
implementation of effective well isolations. Once these activities
have been completed, anticipated early in the second quarter, the
vessel will depart the field and be handed back to the owner.
At Thistle/Deveron, work will continue on the rehabilitation
project alongside ongoing preparations for commencement of the well
abandonment program, which is expected to commence in the fourth
quarter.
On Heather/Broom activities to optimise the well abandonment
programme and ready the rig for decommissioning have continued.
Once completed, plug and abandonment of the development's 41 wells
is expected to begin in the third quarter of 2021, with the work
programme anticipated to continue for approximately three
years.
Malaysia operations
2020 performance summary
In Malaysia, average production was 6,436 Boepd, 25.6% lower
than in 2019. This decrease primarily reflected the impact of a
riser becoming detached at the Seligi Alpha platform which provides
gas lift and injection to the Seligi Bravo platform. This resulted
in a release of gas which initiated an automatic emergency shutdown
of the PM8/Seligi field. The Group's safety systems and emergency
response procedures were successfully implemented, with all
personnel onboard mustered safely. Following an initial
investigation and safety assessment, partial operations were able
to be recommenced within two days, with wells flowing under natural
pressures.
In June, a short planned maintenance shutdown was successfully
completed at PM8/Seligi, with a total outage of two days being
achieved, well within the anticipated original five-day outage.
On Block PM409, an area containing several undeveloped
discoveries and situated close to the Group's existing PM8/Seligi
PSC hub, prospects have been progressed through geotechnical
studies. The initial four-year exploration term of the PSC commits
the partners to the drilling of one well.
2021 performance and outlook
In line with Group expectations, production has remained
impaired for the first two months of 2021, although restoration
efforts have been accelerated, with PM8/Seligi wells coming back
online ahead of schedule. Normal levels are expected to return
during the second half of the year when the damaged riser and
pipeline is anticipated to be replaced.
Over the summer, the Group has scheduled a planned five-day
shutdown to undertake essential maintenance activities.
EnQuest has significant 2P reserves and 2C resources of c.22
MMboe and c.87 MMboe, respectively, in Malaysia. With a number of
low-cost drilling and workover targets having been identified at
PM8/Seligi, the Group expects to resume development drilling in
2022, subject to partner approvals. At PM409, the Group continues
to high grade the prospects in the block to identify suitable
drilling opportunities with the intent for future development.
Financial review
Financial overview
All figures quoted are in US Dollars and relate to Business
performance unless otherwise stated.
2020 was an extremely challenging year with the oil price
collapse of March 2020, the COVID-19 pandemic and the resulting
impacts on the macro-economic environment. As a result, the Company
went through significant changes including decisions to cease
production at some assets and transform the organisation with a
focus on cost and capital expenditure reduction. Notwithstanding
the very challenging environment, the Group delivered on its 2020
production and cost guidance. The early and decisive action to
reduce costs resulted in operating and capital expenditures being
$295.6 million lower than 2019, materially lowering the Group's
free cash flow breakeven.
Revenue and EBITDA were materially lower, impacted by the lower
realised commodity prices and lower production compared to 2019.
The Group's senior credit facility reduced to $377.3 million
including payment in kind ('PIK') following the voluntary early
repayment in 2020 of the $65.0 million amortisation due in April
2021.
Production on a working interest basis decreased by 13.8% to
59,116 Boepd, compared to 68,606 Boepd in 2019. This decrease
primarily reflected the decisions to cease production at the
Heather/Broom and Thistle/Deveron fields, which during 2019
contributed c.6,000 Boepd. In Malaysia, production was lower as a
result of the detached riser system at the Seligi Alpha platform.
At the Dons, production was impacted by a lack of gas lift which is
no longer available from Thistle, combined with underlying natural
declines. As planned, Alma/Galia ceased production in June. These
decreases were partially offset by higher production at Kraken,
driven by a good performance from the FPSO.
Revenue for 2020 was $856.9 million, 49.9% lower than in 2019
($1,711.8 million) reflecting the materially lower realised prices
and lower production. The Group's commodity hedge programme
resulted in realised losses of $6.1 million in 2020 (2019: gains of
$24.8 million).
The Group's operating expenditures of $328.6 million were 36.6%
lower than in 2019 ($518.1 million), primarily reflecting the
Group's focus on cost control and its 2020 transformation
programme, the decisions to cease production at Heather/Broom and
Thistle/Deveron and the cessation of production at Alma/Galia. Unit
operating costs decreased to $15.2/Boe (2019: $20.6/Boe).
Other cost of operations of $53.4 million were lower than in
2019 ($97.5 million), principally as a result of lower cost of
Magnus-related third-party gas purchases reflecting lower market
prices for gas.
EBITDA for 2020 was $550.6 million, down 45.3% compared to 2019
($1,006.5 million), primarily as a result of lower revenue.
2020 2019
$ million $ million
--------------------------------- ---------- -----------
Profit/(loss) from operations
before tax and finance
income/(costs) (20.0) 442.1
--------------------------------- ---------- -----------
Depletion and depreciation 445.9 533.4
--------------------------------- ---------- -----------
Change in provision 95.2 -
--------------------------------- ---------- -----------
Change in well inventories 24.9 14.6
--------------------------------- ---------- -----------
Net foreign exchange (gain)/loss 4.6 16.4
--------------------------------- ---------- -----------
EBITDA 550.6 1,006.5
--------------------------------- ---------- -----------
EnQuest's net debt decreased by $133.3 million to $1,279.7
million at 31 December 2020 (31 December 2019: $1,413.0 million).
This includes $205.8 million of interest that has been capitalised
to the principal of the facilities pursuant to the terms of the
Group's November 2016 refinancing (PIK) (31 December 2019: $133.3
million) (see note 18 for further details).
Net debt/(cash)(1)
----------------------------- ------------------------
31 December 31 December
2020 2019
$ million $ million
----------------------------- ----------- -----------
Bonds 1,048.3 971.9
----------------------------- ----------- -----------
Multi-currency revolving
credit facility ('RCF') 377.3 475.1
----------------------------- ----------- -----------
Sculptor Capital facility 67.7 122.9
----------------------------- ----------- -----------
Tanjong Baram Project
Finance Facility - 31.7
----------------------------- ----------- -----------
SVT Working Capital Facility 9.2 31.9
----------------------------- ----------- -----------
Cash and cash equivalents (222.8) (220.5)
----------------------------- ----------- -----------
Net debt 1,279.7 1,413.0
----------------------------- ----------- -----------
Note:
1 See reconciliation of net debt within the 'Glossary - Non-GAAP measures' starting on page 68
In January 2021, EnQuest made a voluntarily early repayment of
$25.0 million on the RCF, resulting in a final outstanding payment
of $352.3 million, including PIK, due on 1 October 2021.
In June 2020, EnQuest repaid the entire $31.7 million of the
Tanjong Baram Project Finance facility having received the first of
three instalments from Petronas for reimbursement of outstanding
net capital expenditure of around $51.1 million relating to the
Tanjong Baram project. The remaining two reimbursement instalments
were received during the second half of the year (note 5d).
$72.5 million of bond interest was settled through the issue of
additional notes (PIK) and capitalised to the principal of the
facilities in the year, reflecting an average oil price of less
than $65/bbl over the relevant cash payment condition period in
accordance with the terms of the bonds.
The strong production performance at Kraken has driven a $55.2
million reduction in the Sculptor Capital facility in the year.
The Group continues to have unrestricted access to its
unrecognised UK North Sea corporate tax losses, which at the end of
the year increased to $3,183.9 million (2019: $2,903.4 million). In
the current environment, no significant corporation tax or
supplementary charge is expected to be paid on UK operational
activities for the foreseeable future. The Group paid cash
corporate income tax on the Malaysian assets, which will continue
throughout the life of the Production Sharing Contract.
Income statement
Revenue
On average, market prices for crude oil in 2020 were
significantly lower than in 2019. The Group's average realised oil
price excluding the impact of hedging was $41.6/bbl, 35.2% lower
than in 2019 ($64.2/bbl). Revenue is predominantly derived from
crude oil sales, which totalled $779.9 million, 49.6% lower than in
2019 ($1,548.2 million), reflecting the significantly lower oil
prices, a reduction of production and moving from a net overlift to
a net underlift position at the end of the year. Revenue from the
sale of condensate and gas was $60.5 million (2019: $120.2
million), as a result of the significantly lower gas prices.
Tariffs and other income generated $22.6 million (2019: $18.7
million). The Group's commodity hedges and other oil derivatives
contributed $6.1 million of realised losses (2019: gains of $24.8
million), including gains of $6.2 million of non-cash amortisation
of option premiums (2019: gains of $4.9 million) as a result of the
timing at which the hedges were entered into. The Group's average
realised oil price including the impact of hedging was $41.3/bbl in
2020, 36.8% lower than 2019 ($65.3/bbl).
Note: For the reconciliation of realised oil prices see
'Glossary - Non-GAAP measures' starting on page 68
Cost of sales(1)
2020 2019
$ million $ million
---------------------------- ---------- ----------
Production costs 265.5 441.6
---------------------------- ---------- ----------
Tariff and transportation
expenses 63.7 74.8
---------------------------- ---------- ----------
Realised (gain)/loss on
derivatives related to
operating costs (0.6) 1.7
---------------------------- ---------- ----------
Operating costs 328.6 518.1
---------------------------- ---------- ----------
(Credit)/charge relating
to the Group's lifting
position and inventory (34.8) 102.9
---------------------------- ---------- ----------
Depletion of oil and gas
assets 438.2 525.1
---------------------------- ---------- ----------
Other cost of operations 53.5 97.5
---------------------------- ---------- ----------
Cost of sales 785.5 1,243.6
---------------------------- ---------- ----------
Unit operating cost(2) $/Boe $/Boe
---------------------------- ---------- ----------
- Production costs 12.3 17.6
---------------------------- ---------- ----------
- Tariff and transportation
expenses 2.9 3.0
---------------------------- ---------- ----------
Average unit operating
cost 15.2 20.6
---------------------------- ---------- ----------
Notes:
1 See reconciliation of alternative performance measures within
the 'Glossary - Non-GAAP measures' starting on page 68
2 Calculated on a working interest basis
Cost of sales were $785.5 million for the year ended 31 December
2020, 36.8% lower than in 2019 ($1,243.6 million).
Operating costs decreased by $189.5 million, primarily
reflecting the Group's focus on cost control and its 2020
transformation programme, the decisions to cease production at
Heather/Broom and Thistle/Deveron and the cessation of production
at Alma/Galia. Unit operating costs decreased by 26.2% to $15.2/Boe
(2019: $20.6/Boe) as a result of the material reduction in costs
having a greater impact than the lower production in 2020.
The credit relating to the Group's lifting position and
inventory was $34.8 million (2019: charge of $102.9 million). This
primarily reflects a switch to a $3.0 million net underlift
position at 31 December 2020 from a $28.6 million net overlift
position at 31 December 2019.
Depletion expense of $438.2 million was 16.5% lower than in 2019
($525.1 million), mainly reflecting the asset impairments at
half-year 2020 and year-end 2019, along with lower production.
Other cost of operations of $53.5 million were lower than in
2019 ($97.5 million). This primarily reflects the lower cost of
Magnus-related third-party gas purchases following the reduction in
the market price for gas, partially offset by the $24.9 million
inventory write down recognised in the year, which principally
relates to inventory held at assets now scheduled for
decommissioning.
Other income and expenses
Net other expense of $85.3 million (2019: net other expense of
$18.4 million) is primarily due to recognising $83.2 million in
relation to the increase in the decommissioning provision of fully
impaired assets, $12.0 million relating to the change in estimate
of Thistle decommissioning liability and foreign exchange losses of
$4.6 million, partially offset by $10.2 million gain on the
termination of the Tanjong Baram risk service contract.
Finance costs
Finance costs of $179.8 million were 13.0% lower than in 2019
($206.6 million). This decrease was primarily driven by a reduction
of $35.0 million in interest charges associated with the Group's
loans (2020: $32.8 million; 2019: $67.8 million) offset by a $10.9
million increase in bond interest (2020: $73.5 million; 2019: $62.6
million). Other finance costs included lease liability interest of
$50.9 million (2019: $55.7 million), $15.3 million on unwinding of
discount on decommissioning provisions and other liabilities (2019:
$14.1 million), $5.4 million amortisation of arrangement fees for
financing facilities and bonds (2019: $5.7 million) and other
financial expenses of $2.0 million (2019: $2.1 million), primarily
being the cost for surety bonds to provide security for
decommissioning liabilities.
Taxation
The tax credit for 2020 of $172.5 million (2019: $23.6 million
tax charge), excluding exceptional items, is mainly due to the Ring
Fence Expenditure Supplement (RFES) on UK activities generated in
the year.
Remeasurement and exceptional items
Remeasurements and exceptional items resulting in a post-tax net
loss of $599.6 million have been disclosed separately for the year
ended 31 December 2020 (2019: loss of $663.6 million).
Revenue included unrealised gains of $8.8 million in respect of
the mark-to-market movement on the Group's commodity contracts
(2019: unrealised losses of $65.4 million).
Cost of sales included expenses of: $5.9 million in relation to
the PM8/Seligi riser repair provision; $5.8 million in relation to
the Group's transformation costs; and $1.9 million in relation to
unrealised losses on FX derivatives.
Non-cash impairment charges of $422.5 million (2019: $812.4
million) on the Group's oil and gas assets arises from a reduction
in the long-term oil price.
Other income included a $138.2 million gain in relation to the
fair value recalculation of the Magnus contingent consideration
reflecting the reduction in oil price assumption (2019: $15.5
million expense). Other finance costs mainly relates to the
unwinding of contingent consideration from the acquisition of
Magnus and associated infrastructure and interest charged on the
vendor loan of $77.3 million (2019: $57.2 million).
A net tax charge of $232.3 million (2019: credit of $303.5
million) has been presented as exceptional, representing the
non-cash de-recognition of undiscounted deferred tax assets of
$371.1 million given the Group's lower oil price assumptions,
partially offset by the tax impact of the above items. EnQuest
continues to have unrestricted access to its full unrecognised UK
North sea corporate tax losses of $3,183.9 million at 31 December
2020.
IFRS results
The Group's results on an IFRS basis are shown on the Group
Income Statement as 'Reported in the year', being the sum of our
Business performance results and our Remeasurements and exceptional
items, both of which are explained above.
Our IFRS revenue reflects our Business performance revenue, but
adjusted for the impact of unrealised movements on derivative
commodity contracts. Business performance Cost of sales is
similarly adjusted for the impact of unrealised movements on
derivative contracts, together with various exceptional provisions
as noted above. Taking account of these items, and the other
exceptional items included within the Group income statement which
are principally related to impairment charges and the change in
fair value of contingent consideration payable, our IFRS loss from
operations before tax and finance costs was $310.1 million (2019:
loss of $467.8 million), our IFRS loss before tax was $566.0
million (2019: loss of $792.1 million), and our IFRS loss after tax
of $625.8 million (2019: loss of $449.3 million).
Earnings per share
The Group's Business performance basic loss per share was 0.2
cents (2019 profit per share: 13.1 cents) and diluted loss per
share was 0.2 cents (2019 profit per share: 13.0 cents).
The Group's reported basic loss per share was 37.8 cents (2019
loss per share: 27.4 cents) and reported diluted loss per share was
37.8 cents (2019 loss per share: 27.4 cents).
Cash flow and liquidity
Net debt at 31 December 2020 amounted to $1,279.7 million,
including PIK of $205.8 million, compared with net debt of $1,413.0
million at 31 December 2019, including PIK of $133.3 million. The
movement in net debt was as follows:
$ million
------------------------------------ ---------
Net debt 1 January 2020 (1,413.0)
------------------------------------ ---------
Net cash flows from operating
activities 522.1
------------------------------------ ---------
Cash capital expenditure (131.4)
------------------------------------ ---------
Net interest and finance costs
paid (42.2)
------------------------------------ ---------
Finance lease payments (123.0)
------------------------------------ ---------
Repayments on Magnus financing
and profit share (61.8)
------------------------------------ ---------
Net cash received on termination
of Tanjong Baram risk service
contract 51.1
------------------------------------ ---------
Non-cash capitalisation of interest (73.5)
------------------------------------ ---------
Other movements, primarily net
foreign exchange on cash and
debt (8.0)
------------------------------------ ---------
Net debt 31 December 2020 (1) (1,279.7)
------------------------------------ ---------
Note:
1 See reconciliation of alternative performance measures within
the 'Glossary - Non-GAAP measures' starting on page 68
The Group's reported net cash flows from operating activities
for the year ended 31 December 2020 were $522.1 million, down 45.7%
compared to 2019 ($962.3 million). The main drivers for this
decrease were materially lower realised prices and a decrease in
production, partially offset by the significant reduction in
operating expenditure.
Cash outflow on capital expenditure is set out in the table
below:
Year ended Year ended
31 December 31 December
2020 2019
$ million $ million
--------------------------- ------------ ------------
North Sea 127.0 224.4
--------------------------- ------------ ------------
Malaysia 4.4 13.0
--------------------------- ------------ ------------
Exploration and evaluation - 0.1
--------------------------- ------------ ------------
131.4 237.5
--------------------------- ------------ ------------
Cash capital expenditure in 2020 primarily related to Kraken and
Magnus drilling activities.
Balance sheet
The Group's total asset value has decreased by $1,069.9 million
to $3,706.7 million at 31 December 2020 (2019: $4,776.6 million),
mainly due to the impairment charge on the Group's tangible oil and
gas assets and depletion of oil and gas assets. Net current
liabilities have increased to $536.9 million as at 31 December 2020
(2019: $282.7 million). Included in the Group's net current
liabilities are $101.8 million of estimated future obligations
where settlement is subject to the financial performance at Kraken
and Magnus (2019: $178.7 million).
Property, plant and equipment ('PP&E')
PP&E has decreased by $817.0 million to $2,633.9 million at
31 December 2020 from $3,450.9 million at 31 December 2019 (see
note 10). This decrease encompasses the capital additions to
PP&E of $83.6 million, a net increase of $10.2 million for
changes in estimates for decommissioning and other provisions,
offset by non-cash impairments of $422.5 million and depletion and
depreciation charges of $445.9 million, and $42.5 million related
to disposals and the termination of the Tanjong Baram risk service
contract.
The PP&E capital additions during the year, including
capitalised interest, are set out in the table below:
2020
$ million
---------- ----------
North Sea 81.4
---------- ----------
Malaysia 2.2
---------- ----------
83.6
---------- ----------
Trade and other receivables
Trade and other receivables decreased by $160.8 million to
$118.7 million at 31 December 2020 compared with $279.5 million at
31 December 2020. The decrease is driven by a reduction in trade
and joint venture debtors, mainly attributable to shorter
contractual payment terms for cargos lifted at the end of 2020.
Cash and net debt
The Group had $222.8 million of cash and cash equivalents at 31
December 2020 and $1,279.7 million of net debt, including PIK and
capitalised interest of $214.2 million (2019: $220.5 million,
$1,413.0 million and $140.7 million, respectively).
Net debt comprises the following liabilities:
-- $249.2 million principal outstanding on the GBP155.0 million
retail bond, including interest capitalised as PIK of $39.4 million
(2019: $225.7 million and $22.1 million, respectively);
-- $799.2 million principal outstanding on the high yield bond,
including interest capitalised as PIK of $149.2 million (2019:
$746.1 million and $96.1 million, respectively);
-- $377.3 million of credit facility, comprising amounts drawn
down of $360 million and interest capitalised as PIK of $17.3
million (2019: $475.1 million, $460.0 million and $15.1 million,
respectively);
-- $67.7 million on the Sculptor Capital facility, comprising
amounts drawn down of $59.4 million and capitalised interest of
$8.4 million (2019: $122.9 million, $115.5 million and $7.4
million, respectively);
-- $9.2 million relating to the SVT Working Capital Facility (2019: $31.9 million); and
-- $nil relating to the Tanjong Baram Project Finance Facility (2019: $31.7 million).
Provisions
The Group's decommissioning provision increased by $66.3 million
to $778.2 million at 31 December 2020 (2019: $711.9 million). The
movement is due to an increase in changes in estimates of $85.9
million, $7.5 million of additions and $14.5 million unwinding of
discount, partially offset by utilisation of $41.6 million for
decommissioning carried out in the year.
Other provisions, including the Thistle decommissioning
provision, increased by $11.1 million in 2020 to $62.2 million
(2019: $51.1 million). The Thistle decommissioning provision of
$53.1 million is in relation to EnQuest's obligation to make
payments to BP by reference to 7.5% of BP's decommissioning costs
of the Thistle and Deveron fields. Other provisions also include
$5.9 million in relation to the PM8/Seligi riser repair
provision.
Contingent consideration
The contingent consideration related to the Magnus acquisition
decreased by $135.0 million. In 2020, EnQuest paid $74.0 million to
BP (2019: $88.4 million). The payment primarily related to the
$31.0 million partial repayment of the 75% interest vendor loan and
interest and $41.1 million relating to BP's entitlement to share in
the cash flows from the 75% interest. A change in fair value
estimate charge of $138.2 million (2019: $15.5 million) and finance
costs of $77.3 million (2019: $57.2 million) was recognised in the
year.
Income tax
The Group had an income tax receivable of $5.6 million (2019:
$4.1 million payable) related to the net of corporate income tax on
Malaysian assets and North Sea Research and Development Expenditure
Credits.
Deferred tax
The Group's net deferred tax asset has decreased from $555.1
million at 31 December 2019 to $497.6 million at 31 December 2020.
This is driven by non-cash partial de-recognition of undiscounted
deferred tax assets given the Group's lower oil price assumptions
partially offset by other movements in relation to capital
expenditure and Ring Fence Expenditure Supplement. EnQuest
continues to have access to its full unrecognised UK corporate tax
losses carried forward at 31 December 2020 amounting to $3,183.9
million (31 December 2019: $2,903.4 million).
Trade and other payables
Trade and other payables of $255.2 million at 31 December 2020
are $164.7 million lower than at 31 December 2019 ($419.9 million).
The full balance of $255.2 million is payable within one year. This
decrease is driven by a reduced cost base following the Group's
transformation programme and a reduction in the Group's overlift
position.
Leases obligations
As at 31 December 2020, the Group held a lease liability of
$647.8 million (2019: $716.2 million).
Financial risk management
The Group's activities expose it to various financial risks
particularly associated with fluctuations in oil price, foreign
currency risk, liquidity risk and credit risk. The disclosures in
relation to financial risk management objectives and policies,
including the policy for hedging, and the disclosures in relation
to exposure to oil price, foreign currency and credit and liquidity
risk, are included in note 27 of the financial statements.
Going concern disclosure
The Group closely monitors and manages its funding position and
liquidity risk throughout the year, including monitoring forecast
covenant results, to ensure that it has access to sufficient funds
to meet forecast cash requirements. Cash forecasts are regularly
produced and sensitivities considered for, but not limited to,
changes in crude oil prices (adjusted for hedging undertaken by the
Group), production rates and costs. These forecasts and sensitivity
analyses allow management to mitigate liquidity or covenant
compliance risks in a timely manner. Management has also settled
the required term loan amortisations on or ahead of schedule, with
no further scheduled payments required prior to maturity in October
2021 following the voluntary repayment of the April 2021
amortisation in the fourth quarter of 2020.
The Group continues to monitor actively the impact on operations
from COVID-19 and the health, safety and wellbeing of its employees
is its top priority. The Group remains compliant with UK, Malaysia
and Dubai government and industry policy. The Group has also been
working with a variety of stakeholders, including industry and
medical organisations, to ensure its operational response and
advice to its workforce is appropriate and commensurate with the
prevailing expert advice and level of risk. At the time of
publication of EnQuest's full year results, the Group's day-to-day
operations continue without being materially affected by
COVID-19.
The Group's latest approved business plan underpins management's
base case ('Base Case') and is in line with the Group's production
guidance, assumes a refinancing of the existing Revolving Credit
Facility ('RCF') prior to maturity in October 2021 with a new
facility and uses oil price assumptions of $60/bbl from March to
December 2021 and $58/bbl to the end of the first quarter 2022.
The Base Case has been subjected to stress testing by
considering the impact of the following plausible downside risks
(the 'Downside Case'):
-- 10.0% discount to Base Case prices resulting in Downside Case
prices of $54.0/bbl from March to December 2021 and $52.2/bbl for
2022;
-- Production risking of c.4.0% for 2021; and
-- Incremental decommissioning security of $43 million is met
through letters of credit resulting in a reduction in headroom as
letters of credit are drawings under the RCF.
The Base Case and Downside Case indicate that the Group is able
to operate as a going concern with refinanced borrowing facilities
for 12 months from the date of publication of its full year
results. The Directors have also performed reverse stress testing
on the Base Case, with the breakeven price for liquidity in the
Going Concern period being c.$30/bbl under the assumption the
existing facility is refinanced. In addition, under the Base Case
prices, a minimum size of facility or alternative financing
arrangement of approximately $100 million would be required to
maintain positive headroom should the existing facility not be
refinanced.
The quarterly liquidity covenant in the existing facility (the
'Liquidity Test') requires that the Group shows it has sufficient
funds available to meet all liabilities of the Group when due and
payable for the period commencing on each quarter and ending on the
date falling 12 months after the final maturity date of 1 October
2021. The Liquidity Test will be applied for the quarters ended
March 2021 and June 2021. The Liquidity Test assumptions include a
price deck of the average forward oil price curve, minus a 10%
discount, of 15 consecutive business days starting from
approximately the middle of the previous quarter.
Under these prices, the Group forecasts no breaches in the Base
Case for the Liquidity Test. By applying a discount in excess of
29% (19% in addition to the 10% discount stipulated in the Facility
agreement), the Group would breach this covenant, prior to any
mitigations such as asset divestments or other funding options.
Under such an oil price scenario, the covenant breach would
therefore require a covenant waiver to be obtained. The Directors
are confident that waivers from the facility providers would be
forthcoming. Should circumstances arise that differ from the
Group's projections, the Directors believe that a number of
mitigating actions, including refinancing, asset sales or other
funding options, can be executed successfully in the necessary
timeframe to meet debt repayment obligations as they become due and
in order to maintain liquidity.
Within the going concern period, the RCF expires in October 2021
(see note 18). The Directors are confident that the Group will be
able to refinance the RCF based on the Group's Base Case cash flow
projections.
On 4 February 2021, the Group announced it had signed an
agreement with Suncor Energy UK Limited ('Suncor') to purchase
Suncor's entire 26.69% non-operated equity interest in the Golden
Eagle area for an initial consideration of $325 million, excluded
from the Base Case. The Group also advised plans to finance the
transaction through the combination of a new secured debt facility,
an equity raise, and the interim period post-tax cash flows
generated from the economic date of 1 January 2021 to transaction
completion.
A final term sheet has been agreed following bilateral
discussions with DNB and BNP (lead and co-technical banks) and has
been approved by their respective credit committees. DNB and BNP
have also received credit committee approval for material
commitments to the new financing. The Directors are confident they
will be able to complete the new financing given the feedback it
has had from both current lenders and also potential new lenders.
In the unlikely event the Suncor acquisition does not complete, the
Directors are also confident they will be able to negotiate a new
facility based on the Group's existing asset base or alternative
financing arrangements such as a prepayment facility would be
available to bridge any shortfall.
Whilst securing lenders commitment to the new facility remains
on track, the new facility has not been signed at the time of
publication of the Group's results. Although the Directors are
confident that the new facility will be executed, the facility has
not yet been signed; in these circumstances they have to conclude
that this represents a material uncertainty that may cast
significant doubt upon the Group's ability to continue as a going
concern, such that it may not be able to realise its assets and
discharge its liabilities in the normal course of business.
Notwithstanding the material uncertainty as described above,
after making appropriate enquiries and assessing the progress
against the forecast, projections and the status of the mitigating
actions referred to above, and in particular the advanced state of
the proposed refinancing agreement, the Directors have a reasonable
expectation that the Group will continue in operation and meet its
commitments as they fall due over the going concern period.
Accordingly, the Directors continue to adopt the going concern
basis in preparing these financial statements.
Viability statement
The Directors have assessed the viability of the Group over a
three-year period to March 2024. The viability assumptions are
consistent with the going concern assessment, with the additional
inclusion of an oil price of $58/bbl for the remainder of 2022, a
longer term price of $60/bbl and refinancing of both the High Yield
and Retail Bonds in October 2023. This assessment has taken into
account the Group's financial position as at March 2021, the future
projections and the Group's principal risks and uncertainties. The
Directors' approach to risk management, their assessment of the
Group's principal risks and uncertainties, and the actions
management are taking to mitigate these risks are outlined on pages
16 to 25. The period of three years is deemed appropriate as it is
the time horizon across which management constructs a detailed plan
against which business performance is measured, covering repayment
of the Group's term loan and maturation of both its High Yield and
Retail bonds. Notwithstanding the material uncertainty as described
above in the going concern disclosure, based on the Group's
projections, including refinancing of the current facility and of
both the High Yield and Retail bonds, the Directors have a
reasonable expectation that the Group can continue in operation and
meet its liabilities as they fall due over the period to March
2024.
The Base Case has further been stress tested to understand the
impact on the Group's liquidity and financial position of
reasonably possible changes in these risks and/or assumptions.
For the current assessment, the Directors also draw attention to
the specific principal risks and uncertainties (and mitigants)
identified below, which, individually or collectively, could have a
material impact on the Group's viability during the period of
review. In forming this view, it is recognised that such future
assessments are subject to a level of uncertainty that increases
with time and, therefore, future outcomes cannot be guaranteed or
predicted with certainty. The impact of these risks and
uncertainties have been reviewed on both an individual and combined
basis by the Directors, while considering the effectiveness and
achievability of potential mitigating actions.
Oil price volatility
A decline in oil and gas prices would adversely affect the
Group's operations and financial condition. To mitigate oil price
volatility, the Directors have hedged approximately 5 MMbbls at an
average floor price of around $55/bbl in 2021. The Directors, in
line with Group policy, will continue to pursue hedging at the
appropriate time and price.
Access to funding
Prolonged low oil prices, cost increases and production delays
or outages could threaten the Group's liquidity and/or ability to
refinance the RCF. In assessing viability, the Directors recognise
the conclusion that the Group expects to negotiate a new facility
or alternative financing arrangements.
The maturity date of the existing $799 million High Yield Bond
and the GBP186 million Retail Notes (both figures at year end 2020
and inclusive of the PIK notes) is October 2023. The Directors
recognise that refinancing would be required at or before the
maturity date of the bonds, and believe this would be achievable
subject to market conditions at that time. Under the oil price
assumptions outlined above, the total amount of the High Yield Bond
and Retail Notes outstanding at October 2023 would be $954 million
and GBP228 million respectively. If oil prices were to be lower
than those assumptions, then a refinancing of the bonds may require
asset sales or other financing or funding options.
Notwithstanding the principal risks and uncertainties described
above, after making enquiries and assessing the progress against
the forecast, projections and the status of the mitigating actions
referred to above, the Directors have a reasonable expectation that
the Group can continue in operation and meet its commitments as
they fall due over the viability period ending March 2024.
Accordingly, the Directors therefore support this viability
statement.
Risks and uncertainties
Management of risks and uncertainties
Consistent with the Company's purpose, the Board has articulated
EnQuest's strategic vision to be the operator of choice for
maturing and underdeveloped hydrocarbon assets. EnQuest is focused
on delivering on its targets, driving future growth and managing
its capital structure and liquidity.
EnQuest seeks to balance its risk position between investing in
activities that can achieve its near-term targets, including those
associated with reducing emissions, and drive future growth with
the appropriate returns, including any appropriate market
opportunities that may present themselves, and the continuing need
to remain financially disciplined. This combination drives cost
efficiency and cash flow generation, facilitating the continued
reduction in the Group's debt. In this regard, the Board has
developed certain guiding strategic tenets that link with EnQuest's
strategy and appetite for risk. Broadly, these reflect a focus by
the Company on:
-- Maintaining discipline across financial metrics such as
ensuring adequate financial headroom;
-- Enhancing diversity within our portfolio of assets, with a
focus on underdeveloped producing assets and maturing assets with
potential; and
-- Ensuring the quality of the investment decision-making process.
In pursuit of its strategy, EnQuest has to manage a variety of
risks. Accordingly, the Board has established a Risk Management
Framework ('RMF') to enhance effective risk management within the
following Board-approved overarching statements of risk
appetite:
-- The Group makes investments and manages the asset portfolio
against agreed key performance indicators consistent with the
strategic objectives of enhancing net cash flow, reducing leverage,
reducing emissions, managing costs and diversifying its asset
base;
-- The Group seeks to embed a risk culture within the
organisation corresponding to the risk appetite which is
articulated for each of its principal risks;
-- The Group seeks to avoid reputational risk by ensuring that
its operational and HSEA processes, policies and practices reduce
the potential for error and harm to the greatest extent practicable
by means of a variety of controls to prevent or mitigate
occurrence; and
-- The Group sets clear tolerances for all material operational
risks to minimise overall operational losses, with zero tolerance
for criminal conduct.
The Board reviews the Company's risk appetite annually in light
of changing market conditions and the Company's performance and
strategic focus. The Executive Committee periodically reviews and
updates the Group Risk Register based on the individual risk
registers of the business. The Group Risk Register, along with an
assurance mapping and controls review exercise; a risk report
(focused on identifying and mitigating the most critical and
emerging risks through a systematic analysis of the Company's
business, its industry and the global risk environment); and a
continuous improvement plan, is periodically reviewed by the Board
(with senior management) to ensure that key issues are being
adequately identified and actively managed. In addition, the
Group's Safety, Climate and Risk Committee (a sub-Committee of the
Board) provides a forum for the Board to review selected individual
risk areas in greater depth.
As part of its strategic, business planning and risk processes,
the Group considers how a number of macro-economic themes may
influence its principal risks. These are factors about which the
Company should be cognisant of when developing its strategy. They
include, for example, long-term supply and demand trends,
developments in technology, demographics, the financial and
physical risks associated with climate change and how markets and
the regulatory environment may respond, and the decommissioning of
infrastructure in the UK North Sea and other mature basins. These
themes are relevant to the Group's assessments across a number of
its principal risks. The Group will continue to monitor these
themes and the relevant developing policy environment at an
international and national level, adapting its strategy
accordingly. For example, while climate change is now a discrete,
standalone risk within the Group's 'Risk Library', EnQuest remains
conscious of the potential for a number of aspects of climate
change to amplify certain principal risks over time (e.g. in
relation to access to capital markets - see 'Financial' risk on
page 22 - and oil price - see 'Oil and gas prices' risk on page
20). The Group is also conscious that as an operator of mature
producing assets with limited appetite for exploration, it has
limited exposure to investments which do not deliver near-term
returns and is therefore in a position to adapt and calibrate its
exposure to new investments according to developments in relevant
markets. This flexibility also ensures the Group has some inherent
mitigation against the potential impact of "stranded assets".
As part of its evolution of the Group's RMF, the Safety, Climate
and Risk Committee has refreshed its views on all risk areas faced
by the Group (categorising these into a 'Risk Library' of 19
overarching risks). For each risk area, the Committee reviewed
'Risk Bowties' that identified risk causes and impacts and mapped
these to preventative and containment controls used to manage the
risks to acceptable levels (see diagram below).
The Board, supported by the Audit Committee and the Safety,
Climate and Risk Committee, has reviewed the Group's system of risk
management and internal control for the period from 1 January 2020
to the date of this report and carried out a robust assessment of
the Company's emerging and principal risks and the procedures in
place to identify and mitigate these risks. The Board confirms that
the Group complies in this respect with the Financial Reporting
Council's 'Guidance on Risk Management, Internal Control and
Related Financial and Business Reporting'.
Near-term and emerging risks
As outlined above, the Group's RMF is embedded in all levels of
the organisation with asset risk registers, regional and functional
risk registers and ultimately an enterprise level 'Risk Library'.
This integration enables the Group to quickly identify, escalate
and appropriately manage emerging risks.
During 2020, work was undertaken to enhance the integration of
these risk registers to allow management to understand better the
various asset risks and how these ultimately impact on the
enterprise level risk and their associated 'Risk Bowties'. In turn,
this ensures that the preventative and containment controls in
place for a given risk are reviewed and robust based upon the
identified risk profile. It also drives the required prioritisation
of deep dives to be undertaken by the Safety, Climate and Risk
Committee. For example, a number of risks in relation to asset
integrity at an asset level have been escalated, ultimately
resulting in a deep dive of the 'Risk Bowties' in relation to the
enterprise level risks that are impacted by asset integrity risk,
such as HSEA. After careful analysis and assessment, and in light
of the increasing importance of climate change-related issues, the
Board recognised climate change as a discrete, standalone risk
within the 'Risk Library'.
The most relevant near-term and emerging risks, along with the
Group's assessment of their potential impact on the business and
associated required mitigations, have been recognised as
follows:
Risk Appetite
--------------------------- --------------------------------------------------------------------
Climate change EnQuest recognises that
the oil and gas industry,
The Group recognises alongside other key
that climate change stakeholders such as
concerns and related governments, regulators
regulatory developments and consumers, must
could impact a number contribute to reduce
of the Group's principal the impact of carbon-related
risks, such as oil price, emissions on climate
financial, reputational change, and is committed
and fiscal and government to contributing positively
take risks, which are towards the drive to
disclosed later in this net-zero.
report.
------------------------------- ---------------------------------
Mitigation
--------------------------------------------------------------------
Mitigations against The Group has committed
the Group's principal to a 10% reduction in
risks potentially impacted Scope 1 and 2 emissions
by climate change are over three years, from
reported later in this a year-end 2020 baseline,
report. with the achievement
The Group endeavours linked to reward. A
to reduce emissions working group, which
through improving operational reports to the Safety,
performance, minimising Climate and Risk Committee,
flaring and venting has been established
where possible, and to identify and implement
applying appropriate economically viable
and economic improvement emissions savings opportunities
initiatives, noting across the Group's portfolio
the ability to reduce of assets.
carbon emissions will During 2020, the Group
be constrained by the developed a clear ESG
original design of our strategy, which included
later-life assets. a focus on emissions
EnQuest has reported reductions.
on all of the greenhouse The Group's focus on
gas emission sources short-cycle investments
within its operational drives an inherent mitigation
control required under against the potential
the Companies Act 2006 impact of "stranded
(Strategic Report and assets".
Directors' Reports)
Regulations 2013 and
The Companies (Directors'
Report) and Limited
Liability Partnerships
(Energy and Carbon Report)
Regulations 2018.
Risk Appetite
---------------------------- --------------------------------------------------------------------
COVID-19 EnQuest's employee and The Group has no tolerance
contractor workforce for conduct which may
As a responsible operator, are critical to the compromise its reputation
EnQuest continues to delivery of SAFE Results for integrity and competence.
monitor the evolving and EnQuest's success, The Group recognises
situation and consequent and the Group has a that considerable exposure
risks with regard to very low tolerance for to price risk is inherent
the COVID-19 pandemic, operational risks to to its business.
recognising it could its production.
impact a number of the
Group's principal risks,
such as human resources
and oil price, which
are disclosed later
in the key business
risks section of this
report.
At the time of publication
of EnQuest's full-year
results, the Group's
day-to-day operations
continue without being
materially affected.
--------------------------------- -------------------------------
Mitigation
--------------------------------------------------------------------
The Group continues See 'Oil and gas price
to work with a variety risk on page 20 for
of stakeholders, including more information on
industry and medical how the Group mitigates
organisations, to ensure against price risk.
its operational response
and advice to its workforce
is appropriate and commensurate
with the prevailing
expert advice and level
of risk.
Brexit
The Safety, Climate and Risk Committee reviewed management's
assessment of risk and related mitigations associated with the UK's
planned withdrawal from the European Union and was satisfied with
its assessment that there was no material risk to EnQuest's
business.
Key business risks
The Group's principal risks (identified from the 'Risk Library')
are those which could prevent the business from executing its
strategy and creating value for shareholders or lead to a
significant loss of reputation. The Board has carried out a robust
assessment of the principal risks facing the Company, including
those that would threaten its business model, future performance,
solvency or liquidity.
Cognisant of the Group's purpose and strategy, the Board is
satisfied that the Group's risk management system works effectively
in assessing and managing the Group's risk appetite and has
supported a robust assessment by the Directors of the principal
risks facing the Group.
Set out on the following pages are:
-- the principal risks and mitigations;
-- an estimate of the potential impact and likelihood of
occurrence after the mitigation actions, along with how these have
changed in the past year; and
-- an articulation of the Group's risk appetite for each of these principal risks
Amongst these, the key risks the Group currently faces are
materially lower oil prices for an extended period due to any
potential macroeconomic impact of COVID-19 (see 'Oil and gas
prices' risk on page 20), which may impact our ability to refinance
debt and/or execute growth opportunities, and/or a materially lower
than expected production performance for a prolonged period (see
'Production' risk on page 20 and 'Subsurface risk and reserves
replacement' on page 25).
Risk Appetite
-------------------------------- -------------------------------------------------------------------
Health, Safety and Environment The Group's principal The Group's desire is
('HSE') aim is SAFE Results to maintain upper quartile
with no harm to people HSE performance measured
Oil and gas development, and respect for the against suitable industry
production and exploration environment. Should metrics.
activities are by their operational results
very nature complex and safety ever come
with HSE risks covering into conflict, employees
many areas, including have a responsibility
major accident hazards, to choose safety over
personal health and operational results.
safety, compliance with Employees are empowered
regulatory requirements, to stop operations for
asset integrity issues safety-related reasons.
and potential environmental
impacts, including those
associated with climate
change.
Potential impact
Medium (2019 Medium)
Likelihood
Medium (2019 Medium)
There has been no material
change in the potential
impact or likelihood
of this risk. The Group
has a strong, open and
transparent reporting
culture and monitors
both leading and lagging
indicators. However,
in September, there
was a high-potential
incident on the Seligi
Alpha platform resulting
in the shutdown of production.
An extensive investigation
has been undertaken
to determine root causes
and implement actions
to reduce risk of any
re -- occurrence. In
addition, a Company-wide
asset integrity review,
supported by independent
parties, has commenced.
The Group's overall
record on HSE remains
robust.
Their remains a risk
to the availability
of competent people
given the potential
impacts of COVID-19.
-------------------------------- -------------------------------- -------------------------------
Mitigation
-------------------------------- -------------------------------------------------------------------
The Group maintains, EnQuest's HSE Policy
in conjunction with is now fully integrated
its core contractors, across its operated
a comprehensive programme sites and this has enabled
of assurance activities an increased focus on
and has undertaken a HSE. There is a strong
series of deep dives assurance programme
into the Risk Bowties in place to ensure EnQuest
that have demonstrated complies with its Policy
the robustness of the and Principles and regulatory
management process and commitments.
identified opportunities
for improvement. In 2020, an independent
safety review was undertaken
A Group aligned HSE across the Group that
continual improvement reported positively
programme is in place, on the Group's safety
promoting a culture culture with a recognition
of engagement and transparency of a strong commitment
in relation to HSE matters. towards safety and robust
HSE performance is discussed processes in place.
at each Board meeting Given the importance
and the mitigation of of asset integrity,
HSE risk continues to a Company-wide review
be a core responsibility team has been formed
of the Safety, Climate to look at integrity
and Risk Committee. management arrangements
During 2020, the Group at a Group, regional
continued to focus on and asset level to drive
control of major accident improvements in 2021.
hazards and 'SAFE Behaviours'.
The Group continues
In addition, the Group to monitor the evolving
has a positive and transparent situation with regard
relationship with the to the impacts of COVID-19
UK Health and Safety in conjunction with
Executive and Department a variety of stakeholders,
for Business, Energy including industry and
& Industrial Strategy, medical organisations.
and the Malaysian regulator, Appropriate actions
Malaysia Petroleum Management. will continue to be
implemented in accordance
with expert advice and
the level of risk.
-------------------------------- -------------------------------- -------------------------------
Risk Appetite
-------------------------------- -------------------------------------------------------------------
Reputation The Group has no tolerance
for conduct which may
The reputational and compromise its reputation
commercial exposures for integrity and competence.
to a major offshore
incident, including
those related to an
environmental incident,
or non -- compliance
with applicable law
and regulation and/or
related climate change
disclosures, are significant.
Similarly, it is increasingly
important EnQuest clearly
articulates its approach
to and benchmarks its
performance against
relevant and material
ESG factors.
Potential impact
High (2019 High)
Likelihood
Low (2019 Low)
There has been no material
change in the potential
impact or likelihood.
-------------------------------- -------------------------------
Mitigation
-------------------------------------------------------------------
All activities are conducted All personnel are authorised
in accordance with approved to shut down production
policies, standards for safety-related reasons.
and procedures. Interface
agreements are agreed During 2020, the Group
with all core contractors. developed a clear ESG
strategy, with a focus
The Group requires adherence on health and safety
to its Code of Conduct (including asset integrity),
and runs compliance emissions reductions,
programmes to provide looking after its employees,
assurance on conformity positively impacting
with relevant legal the communities in which
and ethical requirements. the Group operates,
upholding a robust RMF
The Group undertakes and acting with high
regular audit activities standards of integrity.
to provide assurance
on compliance with established
policies, standards
and procedures.
All EnQuest personnel
and contractors are
required to pass an
annual anti-bribery,
corruption and anti
-- facilitation of tax
evasion course.
Risk Appetite
------------------------------------ ---------------------------------------------------------------------
Production Since production efficiency production assets in
and meeting production its portfolio, EnQuest
The Group's production targets are core to has a very low tolerance
is critical to its success our business and the for operational risks
and is subject to a Group seeks to maintain to its production (or
variety of risks including: a high degree of operational the support systems
subsurface uncertainties; control over that underpin production).
operating in a mature
field environment; potential
for significant unexpected
shutdowns; and unplanned
expenditure (particularly
where remediation may
be dependent on suitable
weather conditions offshore).
Lower than expected
reservoir performance
or insufficient addition
of new resources may
have a material impact
on the Group's future
growth.
The Group's delivery
infrastructure in the
UK North Sea is, to
a significant extent,
dependent on the Sullom
Voe Terminal.
Longer -- term production
is threatened if low
oil prices or prolonged
field shutdowns and/or
underperformance requiring
high -- cost remediation
bring forward decommissioning
timelines.
Potential impact
High (2019 High)
Likelihood
Medium (2019 Low)
There has been no material
change in the potential
impact; however, the
likelihood has increased
to medium as a result
of a smaller portfolio
and the reduced ability
to counter any downside
risks.
The Group has delivered
within its 2020 guidance
range, mainly reflecting
strong performances
from Kraken and at Scolty/Crathes,
offset by lower than
expected production
in Malaysia following
the incident at PM8/Seligi.
--------------------------------- --------------------------------
Mitigation
---------------------------------------------------------------------
The Group's programme The Sullom Voe Terminal
of asset integrity and has a good safety record
assurance activities and its safety and operational
provide leading indicators performance levels are
of significant potential regularly monitored
issues, which may result and challenged by the
in unplanned shutdowns, Group and other terminal
or which may in other owners and users to
respects have the potential ensure that operational
to undermine asset availability integrity is maintained.
and uptime. The Group Further, EnQuest has
continually assesses continued transforming
the condition of its the Sullom Voe Terminal,
assets and operates including lowering operating
extensive maintenance costs, to ensure it
and inspection programmes remains competitive
designed to minimise and well placed to maximise
the risk of unplanned its useful economic
shutdowns and expenditure. life and support the
The Group monitors both future of the North
leading and lagging Sea.
KPIs in relation to
its maintenance activities The Group actively continues
and liaises closely to explore the potential
with its downstream of alternative transport
operators to minimise options and developing
pipeline and terminal hubs that may provide
production impacts. both risk mitigation
and cost savings.
Production efficiency
is continually monitored The Group also continues
with losses being identified to consider new opportunities
and remedial and improvement for expanding production.
opportunities undertaken
as required. A continual,
rigorous cost focus
is also maintained.
Life of asset production
profiles are audited
by independent reserves
auditors. The Group
also undertakes regular
internal reviews. The
Group's forecasts of
production are risked
to reflect appropriate
production uncertainties.
Risk Appetite
-------------------------------- ----------------------------------------------------------------------
Oil and gas prices The Group recognises
that considerable exposure
A material decline in to this risk is inherent
oil and gas prices adversely to its business.
affects the Group's
operations and financial
condition.
Potential impact
High (2019 High)
Likelihood
High (2019 High)
The potential impact
and likelihood remains
high reflecting the
uncertain economic outlook
due to COVID-19 and
the potential acceleration
of "peak oil" demand.
The Group recognises
that climate change
concerns and related
regulatory developments
are likely to reduce
demand for hydrocarbons
over time. This may
be mitigated by correlated
constraints on the development
of new supply. Further,
oil and gas will remain
an important part of
the energy mix, especially
in developing regions.
----------------------------------- -------------------------------
Mitigation
----------------------------------------------------------------------
This risk is being mitigated In order to develop
by a number of measures its resources, the Group
including hedging the needs to be able to
oil price, and institutionalising fund the required investment.
a lower cost base. The Group will therefore
regularly review and
As an operator of mature implement suitable policies
producing assets with to hedge against the
limited appetite for possible negative impact
exploration, the Group of changes in oil prices,
has limited exposure while remaining within
to investments which the limits set by its
do not deliver near-term term loan and revolving
returns and is therefore credit facility.
in a position to adapt
and calibrate its exposure The Group has an established
to new investments according in-house trading and
to developments in relevant marketing function to
markets. enable it to enhance
its ability to mitigate
The Group monitors oil the exposure to volatility
price sensitivity relative in oil prices.
to its capital commitments
and has a policy which Further, as described
allows hedging of its previously, the Group's
production. As at 24 focus on production
March 2021, the Group efficiency supports
had hedged approximately mitigation of a low
5 MMbbls. This ensures oil price environment.
that the Group will
receive a minimum oil
price for its production.
Risk Appetite
---------------------------------- -----------------------------------------------------------------
IT security and resilience The Group endeavours data, impact operations,
to provide a secure or destabilise its financial
The Group is exposed IT environment that systems; it has a very
to risks arising from is able to resist and low appetite for this
interruption to, or withstand any attacks risk.
failure of, IT infrastructure. or unintentional disruption
The risks of disruption that may compromise
to normal operations sensitive
range from loss in functionality
of generic systems (such
as email and internet
access) to the compromising
of more sophisticated
systems that support
the Group's operational
activities. These risks
could result from malicious
interventions such as
cyber-attacks.
Potential impact
Medium (2019 Medium)
Likelihood
Medium (2019 Low)
There has been no change
to the potential impact.
However, the likelihood
has increased reflecting
an increase in personnel
working from home.
----------------------------- --------------------------------
Mitigation
-----------------------------------------------------------------
The Group has established The Safety, Climate
IT capabilities and and Risk Committee undertook
endeavours to be in additional analyses
a position to defend of cyber -- security
its systems against risks in 2020.
disruption or attack.
The Group has a dedicated
cyber -- security manager
and work on assessing
the cyber-security environment
and implementing improvements
as necessary will continue
during 2021.
Risk Appetite
--------------------------- ---------------------------------------------------------------------
Human resources As a low-cost, lean The Group recognises
organisation, the Group that the benefits of
The Group's success relies on motivated a lean, flexible and
continues to be dependent and high -- quality diverse organisation
upon its ability to employees to achieve requires creativity
attract and retain key its targets and manage and agility to assure
personnel and develop its risks. against the risk of
organisational capability skills shortages.
to deliver strategic
growth. Industrial action
across the sector, or
the availability of
competent people given
the potential impacts
of COVID-19, could also
impact the operations
of the Group.
Potential impact
Medium (2019 Medium)
Likelihood
Medium (2019 High)
The impact is unchanged;
the likelihood is lower
due to the downturn
in the industry.
-------------------------------- ---------------------------------
Mitigation
---------------------------------------------------------------------
The Group has established The Group recognises
an able and competent that there is a gender
employee base to execute pay gap within the organisation
its principal activities. but that there is no
In addition, the Group issue with equal pay
seeks to maintain good for the same tasks and
relationships with its also that fewer young
employees and contractor people may join the
companies and regularly industry due to climate
monitors the employment change-related factors.
market to provide remuneration EnQuest aims to attract
packages, bonus plans the best talent, recognising
and long-term share-based the value and importance
incentive plans that of diversity.
incentivise performance
and long-term commitment Executive and senior
from employees to the management retention,
Group. succession planning
and development remain
The Group recognises important priorities
that its people are for the Board. It is
critical to its success a Board -- level priority
and so is continually that executive and senior
evolving EnQuest's end management possess the
-- to -- end people appropriate mix of skills
management processes, and experience to realise
including recruitment the Group's strategy;
and selection, career succession planning
development and performance therefore remains a
management. key priority.
This ensures that EnQuest Following its introduction
has the right person in 2019, the Group employee
for the job and that forum has continued
appropriate training, to add to EnQuest's
support and development employee communication
opportunities are provided, and engagement strategy,
with feedback collated improving interaction
to drive continuous between the workforce
improvement whilst delivering and the Board.
SAFE Results.
The Group continues
The culture of the Group to monitor the evolving
is an area of ongoing situation with regard
focus and employee surveys to the impacts of COVID-19
and forums have been in conjunction with
undertaken to understand a variety of stakeholders,
employees' views on including industry and
a number of key areas medical organisations.
in order to develop Appropriate actions
appropriate action plans. will continue to be
implemented in accordance
The Group also maintains with expert advice and
market -- competitive the prevailing level
contracts with key suppliers of risk.
to support the execution
of work where the necessary
skills do not exist
within the Group's employee
base.
Risk Appetite
-------------------------------- ----------------------------------------------------------------
Financial The Group recognises complying with its obligations
that significant leverage to finance providers
Inability to fund financial was required to fund while delivering shareholder
commitments or maintain its growth as low oil value, recognising that
adequate cash flow and prices impacted revenues. reasonable assumptions
liquidity and/or reduce However, it is intent relating to external
costs. on further reducing risks need to be made
its leverage levels, in transacting with
The outstanding amount maintaining liquidity, finance providers.
on the Group's term enhancing profit margins,
loan and revolving credit controlling costs and
facility at 31 December
2020 was $377.3 million
(including payment in
kind interest) which
requires repayment or
refinancing by October
2021. While the Board
remains confident it
will be able to complete
a refinancing as part
of the funding arrangements
associated with the
Golden Eagle area acquisition,
significant reductions
in the oil price or
material reductions
in production will likely
have a material impact
on the Group's ability
to repay or refinance
the loan facility in
2021. The Group's term
loan and revolving credit
facility also contains
certain financial covenants
(based on the ratio
of indebtedness incurred
under the term loan
and revolving facility
to EBITDA, finance charges
to EBITDA and a requirement
for liquidity testing).
Prolonged low oil prices,
cost increases, including
those related to an
environmental incident,
and production delays
or outages, could threaten
the Group's liquidity
and/or ability to comply
with relevant covenants.
Similar conditions could
impact the Group's ability
to refinance the bonds
ahead of maturity in
October 2023. Further
information is contained
in the Financial review,
particularly within
the going concern and
viability disclosures
on pages 14 and 15.
Potential impact
High (2019 High)
Likelihood
High (2019 High)
There is no change to
the potential impact
or likelihood, reflecting
the continued economic
uncertainty and potential
impact of oil price
fluctuations. The Group
has made material progress
in reducing its term
loan facility ahead
of schedule, and has
voluntarily repaid early
a further $25.0 million
in January 2021. There
is potential for the
availability and cost
of capital to increase
and insurance availability
to erode, as factors
such as climate change
and other ESG concerns
and oil price volatility
may reduce investors'
and insurers' acceptable
levels of oil and gas
sector exposure, and
the cost of emissions
trading certificates
may trend higher along
with insurers' reluctance
to provide surety bonds
for decommissioning,
thereby requiring the
Group to fund decommissioning
security through its
balance sheet.
----------------------------- -------------------------------
Mitigation
----------------------------------------------------------------
Debt reduction is a The Group is continuing
strategic priority. to enhance its financial
During 2020, the Group position through maintaining
repaid a total of $100.0 a focus on controlling
million of the term and reducing costs through
facility, with the $65.0 supplier renegotiations,
million due in April assessing counterparty
2021 voluntarily repaid credit risk, hedging
early. and trading, cost-cutting
and rationalisation.
These steps, together
with other mitigating Where costs are incurred
actions available to by external service
management, are expected providers, the Group
to provide the Group actively challenges
with sufficient liquidity operating costs. The
to strengthen its balance Group also maintains
sheet for longer -- a framework of internal
term growth. controls.
Ongoing compliance with The quick and decisive
the financial covenants actions management took
under the Group's term following the combined
loan and revolving credit impacts of the COVID-19
facility is actively pandemic, the oil price
monitored and reviewed. decline and resulting
economic crisis in early
EnQuest generates operating 2020 have materially
cash inflow from the lowered the Group's
Group's producing assets. free cash flow breakeven.
The Group reviews its
cash flow requirements
on an ongoing basis
to ensure it has adequate
resources for its needs.
Risk Appetite
---------------------------------- ---------------------------------------------------------------------
Fiscal risk and government The Group faces an uncertain Due to the nature of
take macro -- economic and such risks and their
Unanticipated changes regulatory environment. relative unpredictability,
in the regulatory or it must be tolerant
fiscal environment can of certain inherent
affect the Group's ability exposure.
to deliver its strategy/business
plan and potentially
impact revenue and future
developments.
Potential impact
High (2019 High)
Likelihood
Medium (2019 Medium)
There has been no material
change in the potential
impact or likelihood,
although the exit of
the UK from the European
Union may impact the
regulatory environment
going forward, for example
by affecting the cost
of emissions trading
certificates.
---------------------------------- ---------------------------------- -------------------------------
Mitigation
---------------------------------- ---------------------------------------------------------------------
It is difficult for All business development
the Group to predict or investment activities
the timing or severity recognise potential
of such changes. However, tax implications and
through Oil & Gas UK the Group maintains
and other industry associations, relevant internal tax
the Group engages with expertise.
government and other
appropriate organisations At an operational level,
in order to keep abreast the Group has procedures
of expected and potential to identify impending
changes; the Group also changes in relevant
takes an active role regulations to ensure
in making appropriate legislative compliance.
representations.
---------------------------------- ---------------------------------- -------------------------------
Risk Appetite
---------------------------------- ---------------------------------------------------------------------
Project execution and The efficient delivery While the Group necessarily
delivery of projects has been assumes significant
The Group's success a key feature of the risk when it sanctions
will be partially dependent Group's long -- term a new project (for example,
upon the successful strategy. by incurring costs against
execution and delivery oil price assumptions),
of potential future The Group's appetite or a decommissioning
projects, including is to identify and implement programme, it requires
decommissioning in the short -- cycle development that risks to efficient
UK, that are undertaken. projects such as infill project delivery are
drilling and near-field minimised.
Potential impact tie-backs.
Medium (2019 Medium)
Likelihood
Low (2019 Low)
The potential impact
and likelihood remain
unchanged. As the Group
focuses on reducing
its debt, its current
appetite is to pursue
short-cycle development
projects and to manage
its UK decommissioning
projects over an extended
period of time.
---------------------------------- -------------------------------
Mitigation
---------------------------------------------------------------------
The Group has project The Group also engages
teams which are responsible third -- party assurance
for the planning and experts to review, challenge
execution of new projects and, where appropriate,
with a dedicated team make recommendations
for each development. to improve the processes
for project management,
The Group has detailed cost control and governance
controls, systems and of major projects.
monitoring processes
in place, notably the EnQuest ensures that
Capital Projects Delivery responsibility for delivering
Process, to ensure that time-critical supplier
deadlines are met, costs obligations and lead
are controlled and that times are fully understood,
design concepts and acknowledged and proactively
the Field Development managed by the most
Plan are adhered to senior levels within
and implemented. These supplier organisations.
are modified when circumstances
require and only through
a controlled management
of change process and
with the necessary internal
and external authorisation
and communication.
The Group's UK decommissioning
programmes are managed
by a dedicated directorate
with an experienced
team who are driven
safely to deliver projects
at the lowest possible
cost and associated
emissions.
Risk Appetite
---------------------------------- ------------------------------------------------------------------------
Portfolio concentration Although the extent concentrated in the
of portfolio concentration UK North Sea and therefore
The Group's assets are is moderated by production this risk remains intrinsic
primarily concentrated generated internationally, to the Group.
in the UK North Sea the majority of the
around a limited number Group's assets remain
of infrastructure hubs relatively
and existing production
(principally oil) is
from mature fields.
This amplifies exposure
to key infrastructure
(including ageing pipelines
and terminals), political/fiscal
changes and oil price
movements.
Potential impact
High (2019 High)
Likelihood
High (2019 High)
The Group is currently
focused on oil production
and does not have significant
exposure to gas or other
sources of income.
The decisions taken
to accelerate cessation
of production at a number
of the Group's assets
has further reduced
the number of producing
assets and so increased
portfolio concentration
in the near term.
During the year, the
Group signed a sales
and purchase agreement
with Equinor to purchase
a 40.81% operating interest
in the Bressay oil field
in the UK North Sea,
with the transaction
completing in January
2021. Furthermore, in
February 2021, the Group
announced it had signed
an agreement with Suncor
Energy UK Limited ('Suncor')
to purchase Suncor's
entire 26.69% non-operated
equity interest in the
Golden Eagle area. Separately,
a number of licence
awards were granted
to EnQuest during the
32nd Offshore licensing
round.
The Group continues
to assess acquisition
growth opportunities
with a view to improving
its asset diversity
over time.
------------------------------------ --------------------------------
Mitigation
------------------------------------------------------------------------
This risk is mitigated disposals and divesting,
in part through acquisitions. executing development
For all acquisitions, projects, making international
the Group uses a number acquisitions, expanding
of business development hubs and potentially
resources, both in the investing in gas assets
UK and internationally, or export capability
to liaise with vendors/governments where such opportunities
and evaluate and transact are consistent with
acquisitions. This includes the Group's focus on
performing extensive enhancing net revenues,
due diligence (using generating cash flow
in-house and external and strengthening the
personnel) and actively balance sheet.
involving executive
management in reviewing In February 2021, the
commercial, technical Group announced it had
and other business risks signed an agreement
together with mitigation to farm-down an 85%
measures. equity interest in and
transfer operatorship
The Group also constantly of the Eagle discovery
keeps its portfolio to Anasuria Hibiscus
under rigorous review UK Limited. The transaction
and, accordingly, actively is subject to customary
considers the potential regulatory and third-party
for making approvals.
Risk Appetite
---------------------------- ----------------------------------------------------------------
Joint venture partners The Group requires partners of partners and evaluates
of high integrity. It this aspect carefully
Failure by joint venture recognises that it must as part of every investment
parties to fund their accept a degree of exposure decision.
obligations. to the credit worthiness
Dependence on other
parties where the Group
is non-operator.
Potential impact
Medium (2019 Medium)
Likelihood
Low (2019 Low)
There has been no material
change in the potential
impact. The likelihood
has also been maintained
reflecting the Group's
current low exposure
to capital -- intensive
projects requiring funding
from third parties.
------------------------------- -----------------------------
Mitigation
----------------------------------------------------------------
The Group operates regular The Group generally
cash call and billing prefers to be the operator.
arrangements with its
co-venturers to mitigate The Group maintains
the Group's credit exposure regular dialogue with
at any one point in its partners to ensure
time and keeps in regular alignment of interests
dialogue with each of and to maximise the
these parties to ensure value of joint venture
payment. assets, taking account
of the impact of any
Risk of default is mitigated wider developments (e.g.
by joint operating agreements 'Brexit').
allowing the Group to
take over any defaulting
party's share in an
operated asset and rigorous
and continual assessment
of the financial situation
of partners.
Risk Appetite
------------------------------- ------------------------------------------------------------
Subsurface risk and Reserves replacement assumption of risk in
reserves replacement is an element of the relation to the key
sustainability of the activities required
Failure to develop its Group and its ability to deliver reserves
contingent and prospective to grow. The Group has growth, such as drilling
resources or secure some tolerance for the and acquisitions.
new licences and/or
asset acquisitions and
realise their expected
value.
Potential impact
High (2019 High)
Likelihood
Medium (2019 Medium)
There has been no material
change in the potential
impact or likelihood.
Low oil prices or prolonged
field shutdowns requiring
high-cost remediation
which accelerate cessation
of production can potentially
affect development of
contingent and prospective
resources and/or reserves
certifications.
------------------------------ --------------------------
Mitigation
------------------------------------------------------------
The Group puts a strong The Group continues
emphasis on subsurface to consider potential
analysis and employs opportunities to acquire
industry -- leading new production resources
professionals. that meet its investment
criteria.
The Group continues
to recruit in a variety
of technical positions
which enables it to
manage existing assets
and evaluate the acquisition
of new assets and licences.
All analysis is subject
to internal and, where
appropriate, external
review and relevant
stage gate processes.
All reserves are currently
externally reviewed
by a Competent Person.
The Group has material
reserves and resources
at Magnus, Kraken and
PM8/Seligi that it believes
can primarily be accessed
through low-cost sub-sea
drilling and tie-backs
to existing infrastructure.
EnQuest continues to
evaluate the substantial
2C resources at PM409
to identify future drilling
prospects. PM409 is
contiguous to the Group's
existing PM8/Seligi
PSC, providing low-cost
tie-back opportunities
to the Group's existing
Seligi main production
hub.
Risk Appetite
------------------------------ --------------------------------------------------------------
Competition The Group operates in
The Group operates in a mature industry with
a competitive environment well-established competitors
across many areas, including and aims to be the leading
the acquisition of oil operator in the sector.
and gas assets, the
marketing of oil and
gas, the procurement
of oil and gas services
and access to human
resources.
Potential impact
High (2019 High)
Likelihood
High (2019 High)
The potential impact
and likelihood have
remained unchanged,
with a number of competitors
assessing the acquisition
of available oil and
gas assets and the rising
potential for consolidation
(e.g. through reverse
mergers).
------------------------------ ----------------------------
Mitigation
--------------------------------------------------------------
The Group has strong A recent example of
technical, commercial the marketing and trading
and business development group's capability has
capabilities to ensure been moving Kraken from
that it is well positioned the crude oil market
to identify and execute into fuel oil.
potential acquisition
opportunities, utilising In addition, the marketing
innovative structures and trading group is
as may be appropriate. responsible for the
Company's commodity
The Group maintains price risk management
good relations with activities in accordance
oil and gas service with the Group's business
providers and constantly strategy.
keeps the market under
review. EnQuest has
a dedicated marketing
and trading group of
experienced professionals
responsible for maintaining
relationships across
relevant energy markets,
thereby ensuring the
Company achieves the
highest possible value
for its production.
Risk Appetite
------------------------------- -------------------------------------------------------------------
International business In light of its long-term However, such tolerance
growth strategy, the does not impair the
While the majority of Group seeks to expand Group's commitment to
the Group's activities and diversify its production comply with legislative
and assets are in the (geographically and and regulatory requirements
UK, the international in terms of quantum); in the jurisdictions
business is still material. as such, it is tolerant in which it operates.
The Group's international of assuming certain Opportunities should
business is subject commercial risks which enhance net revenues
to the same risks as may accompany the opportunities and facilitate strengthening
the UK business (e.g. it pursues. of the balance sheet.
HSEA, production and
project execution);
however, there are additional
risks that the Group
faces, including security
of staff and assets,
political, foreign exchange
and currency control,
taxation, legal and
regulatory, cultural
and language barriers
and corruption.
Potential impact
Medium (2019 Medium)
Likelihood
Medium (2019 Medium)
There has been no material
change in the impact
or likelihood.
--------------------------------- ------------------------------
Mitigation
-------------------------------------------------------------------
Prior to entering a Where appropriate, the
new country, EnQuest risks may be mitigated
evaluates the host country by entering into a joint
to assess whether there venture with partners
is an adequate and established with local knowledge
legal and political and experience.
framework in place to
protect and safeguard After country entry,
first its expatriate EnQuest maintains a
and local staff and, dialogue with local
second, any investment and regional government,
within the country in particularly with those
question. responsible for oil,
energy and fiscal matters,
When evaluating international and may obtain support
business risks, executive from appropriate risk
management reviews commercial, consultancies.
technical, ethical and
other business risks, When there is a significant
together with mitigation change in the risk to
and how risks can be people or assets within
managed by the business a country, the Group
on an ongoing basis. takes appropriate action
to safeguard people
EnQuest looks to employ and assets.
suitably qualified host
country staff and work
with good-quality local
advisers to ensure it
complies with national
legislation, business
practices and cultural
norms, while at all
times ensuring that
staff, contractors and
advisers comply with
EnQuest's business principles,
including those on financial
control, cost management,
fraud and corruption.
Stefan Ricketts
Company Secretary
The Strategic report was approved by the Board and signed on its
behalf by the Company Secretary on 24 March 2021.
KEY PERFORMANCE INDICATORS
2020 2019 2018
--------------------------------------------- -------- -------- --------
ESG metrics:
Group LTIF(1) 0.22 0.57 0.43
Emissions (kilo-tonnes of CO(2) equivalent) 1,342.8 1,511.6 1,802.4
--------------------------------------------- -------- -------- --------
Business performance data:
Production (Boepd) 59,116 68,606 55,447
Unit opex (production and transportation
costs) ($/Boe)(2) 15.2 20.6 23.0
EBITDA ($ million)(2) 550.6 1,006.5 716.3
Cash expenditures ($ million) 173.0 248.6 230.2
Capital(2) 131.4 237.5 220.2
Abandonment 41.6 11.1 10.0
--------------------------------------------- -------- -------- --------
Reported data:
Cash generated from operations ($ million) 567.8 994.6 788.6
Net debt including PIK ($ million)(2) 1,279.7 1,413.0 1,774.5
Net 2P reserves (MMboe) 189 213 245
--------------------------------------------- -------- -------- --------
(1) Lost time incident frequency represents the number of
incidents per million exposure hours worked (based on 12 hours for
offshore and eight hours for onshore )
(2) See reconciliation of alternative performance measures
within the 'Glossary - Non-GAAP measures' starting on page 68
OIL AND GAS RESERVES AND RESOURCES
EnQuest oil and gas reserves and resources
UKCS(13) Other regions(13) Total(13)
------------ ------------------- ---------
MMboe MMboe MMboe MMboe MMboe
------------------------------------- ----- ----- --------- -------- ---------
Proven and probable reserves(1,
2, 3 and 4)
----- ----- --------- -------- ---------
At 31 December 2019 190 22 213
----- ----- --------- -------- ---------
Revisions of previous estimates
----- ----- --------- -------- ---------
Cessation of production(5) (15) -
----- ----- --------- -------- ---------
Other revisions and transfers from
contingent resources(6) 10 3
----- ----- --------- -------- ---------
(5) 3 (2)
----- ----- --------- -------- ---------
Production:
----- ----- --------- -------- ---------
Export meter (20) (3)
----- ----- --------- -------- ---------
Volume adjustments(7) 0 1
----- ----- --------- -------- ---------
(19) (2) (22)
------------------------------------- ----- ----- --------- -------- ---------
Total proven and probable reserves
at 31 December 2020(8) 166 22 189
------------------------------------- ----- ----- --------- -------- ---------
Contingent resources(1, 2 and 9)
----- ----- --------- -------- ---------
At 31 December 2019 97 76 173
----- ----- --------- -------- ---------
Revisions of previous estimates
----- ----- --------- -------- ---------
Cessation of production(5) (15) -
----- ----- --------- -------- ---------
Other revisions(10) - 16
----- ----- --------- -------- ---------
(15) 16 1
----- ----- --------- -------- ---------
Promoted to reserves(11) (5) (5) (10)
------------------------------------- ----- ----- --------- -------- ---------
Total contingent resources at 31
December 2020 77 87 164
------------------------------------- ----- ----- --------- -------- ---------
Acquisitions and disposals(12) 115 - 115
------------------------------------- ----- ----- --------- -------- ---------
Total contingent resources 192 87 279
------------------------------------- ----- ----- --------- -------- ---------
Notes:
1 Reserves are quoted on a net entitlement basis, resources are
quoted on a working interest basis
2 Proven and probable reserves and contingent resources have
been assessed by the Group's internal reservoir engineers,
utilising geological,
geophysical, engineering and financial data
3 The Group's proven and probable reserves have been audited by
a recognised Competent Person in accordance with the definitions
set out under the 2018 Petroleum Resources Management System and
supporting guidelines issued by the Society of Petroleum
Engineers
4 All UKCS volumes are presented pre-SVT value adjustment
5 Accelerated cessation of production at Thistle/Deveron and the
Dons
6 Technical revisions and transfers from 2C resources at Kraken,
Magnus and PM8/Seligi
7 Correction of export to sales volumes
8 The above proven and probable reserves include c.6 MMboe that
will be consumed as fuel gas on Magnus
9 Contingent resources relate to technically recoverable
hydrocarbons for which commerciality has not yet been determined
and are stated on a best technical case or '2C' basis
10 Additional contingent resources from PM409
11 Kraken, Magnus and PM8/Seligi opportunity maturation
12 Acquisition of 40.81% interest in Bressay agreed in July 2020
(completed on 20 January 2021)
13 Rounding may apply
Group Income Statement
For the year ended 31 December 2020
2020 2019
----------------------- ----- ----------------------------------------- -------------------------------------------
Remeasurements Remeasurements
and exceptional and exceptional
Business items (note Reported Business items (note Reported
performance 4) in year performance 4) in year
Notes $'000 $'000 $'000 $'000 $'000 $'000
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Revenue and other
operating
income 5(a) 856,870 8,778 865,648 1,711,834 (65,375) 1,646,459
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Cost of sales 5(b) (785,455) (13,626) (799,081) (1,243,570) (378) (1,243,948)
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Gross profit/(loss) 71,415 (4,848) 66,567 468,264 (65,753) 402,511
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Net impairment to oil
and
gas assets 4 - (422,495) (422,495) - (812,448) (812,448)
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
General and
administration
expenses 5(c) (6,105) - (6,105) (7,661) - (7,661)
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Other income 5(d) 16,304 138,249 154,553 3,446 - 3,446
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Other expenses 5(e) (101,633) (956) (102,589) (21,881) (31,735) (53,616)
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Profit/(loss) from
operations
before tax and finance
income/(costs) (20,019) (290,050) (310,069) 442,168 (909,936) (467,768)
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Finance costs 6 (179,818) (77,259) (257,077) (206,596) (57,165) (263,761)
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Finance income 6 1,171 - 1,171 2,416 - 2,416
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Profit/(loss) before
tax (198,666) (367,309) (565,975) 237,988 (967,101) (729,113)
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Income tax 7 172,479 (232,306) (59,827) (23,648) 303,460 279,812
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Profit/(loss) for the
year
attributable to owners
of the parent (26,187) (599,615) (625,802) 214,340 (663,641) (449,301)
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
Total comprehensive
loss
for the year,
attributable
to owners of the
parent (625,802) (449,301)
----------------------- ----- ------------ ---------------- --------- ------------ ---------------- -----------
There is no comprehensive income attributable to the
shareholders of the Group other than the loss for the year. Revenue
and operating (loss)/profit are all derived from continuing
operations.
Earnings per share 8 $ $ $ $
------------------- ------- ------- ------ -------
Basic (0.016) (0.378) 0.131 (0.274)
------------------- ------- ------- ------ -------
Diluted (0.016) (0.378) 0.130 (0.274)
------------------- ------- ------- ------ -------
The attached notes 1 to 30 form part of these Group financial
statements.
Group Balance Sheet
At 31 December 2020
2020 2019
Notes $'000 $'000
------------------------------ ----- ---------- ---------
ASSETS
------------------------------ ----- ---------- ---------
Non-current assets
------------------------------ ----- ---------- ---------
Property, plant and equipment 10 2,633,917 3,450,929
------------------------------ ----- ---------- ---------
Goodwill 11 134,400 134,400
------------------------------ ----- ---------- ---------
Intangible oil and gas assets 12 27,546 27,553
------------------------------ ----- ---------- ---------
Deferred tax assets 7(c) 503,946 576,038
------------------------------ ----- ---------- ---------
Other financial assets 19 7 11
------------------------------ ----- ---------- ---------
3,299,816 4,188,931
------------------------------ ----- ---------- ---------
Current assets
------------------------------ ----- ---------- ---------
Inventories 13 59,784 78,644
------------------------------ ----- ---------- ---------
Trade and other receivables 16 118,715 279,502
------------------------------ ----- ---------- ---------
Current tax receivable 5,601 -
------------------------------ ----- ---------- ---------
Cash and cash equivalents 14 222,830 220,456
------------------------------ ----- ---------- ---------
Other financial assets 19 - 9,083
------------------------------ ----- ---------- ---------
406,930 587,685
------------------------------ ----- ---------- ---------
TOTAL ASSETS 3,706,746 4,776,616
------------------------------ ----- ---------- ---------
EQUITY AND LIABILITIES
------------------------------ ----- ---------- ---------
Equity
------------------------------ ----- ---------- ---------
Share capital and premium 20 345,420 345,420
------------------------------ ----- ---------- ---------
Merger reserve 20 - 662,855
------------------------------ ----- ---------- ---------
Share-based payment reserve 20 1,016 (1,085)
------------------------------ ----- ---------- ---------
Retained earnings 20 (411,076) (448,129)
------------------------------ ----- ---------- ---------
TOTAL EQUITY (64,640) 559,061
------------------------------ ----- ---------- ---------
Non-current liabilities
------------------------------ ----- ---------- ---------
Borrowings 18 37,854 493,424
------------------------------ ----- ---------- ---------
Bonds 18 1,045,041 966,231
------------------------------ ----- ---------- ---------
Leases liability 24 548,407 614,818
------------------------------ ----- ---------- ---------
Contingent consideration 22 448,384 545,550
------------------------------ ----- ---------- ---------
Provisions 23 741,453 706,190
------------------------------ ----- ---------- ---------
Deferred tax liabilities 7(c) 6,385 20,919
------------------------------ ----- ---------- ---------
2,827,524 3,347,132
------------------------------ ----- ---------- ---------
Current liabilities
------------------------------ ----- ---------- ---------
Borrowings 18 414,430 165,589
------------------------------ ----- ---------- ---------
Leases liability 24 99,439 101,348
------------------------------ ----- ---------- ---------
Contingent consideration 22 73,877 111,711
------------------------------ ----- ---------- ---------
Provisions 23 98,954 56,769
------------------------------ ----- ---------- ---------
Trade and other payables 17 255,155 419,855
------------------------------ ----- ---------- ---------
Other financial liabilities 19 2,007 11,073
------------------------------ ----- ---------- ---------
Current tax payable - 4,078
------------------------------ ----- ---------- ---------
943,862 870,423
------------------------------ ----- ---------- ---------
TOTAL LIABILITIES 3,771,386 4,217,555
------------------------------ ----- ---------- ---------
TOTAL EQUITY AND LIABILITIES 3,706,746 4,776,616
------------------------------ ----- ---------- ---------
The attached notes 1 to 30 form part of these Group financial
statements.
The financial statements were approved by the Board of Directors
and authorised for issue on 24 March 2021 and signed on its behalf
by:
Jonathan Swinney
Chief Financial Officer
Group Statement of Changes in Equity
For the year ended 31 December 2020
Share
capital Share-based
and share Merger payments Retained
premium reserve reserve earnings Total
$'000 $'000 $'000 $'000 $'000
-------------------------------------------- ---------- --------- ----------- --------- ----------
Balance at 1 January 2019 345,331 662,855 (6,884) 1,172 1,002,474
-------------------------------------------- ---------- --------- ----------- --------- ----------
Profit/(loss) for the year - - - (449,301) (449,301)
-------------------------------------------- ---------- --------- ----------- --------- ----------
Total comprehensive loss for the year - - - (449,301) (449,301)
-------------------------------------------- ---------- --------- ----------- --------- ----------
Share-based payment - - 5,888 - 5,888
-------------------------------------------- ---------- --------- ----------- --------- ----------
Shares issued on behalf of Employee Benefit
Trust 89 - (89) - -
-------------------------------------------- ---------- --------- ----------- --------- ----------
Balance at 31 December 2019 345,420 662,855 (1,085) (448,129) 559,061
-------------------------------------------- ---------- --------- ----------- --------- ----------
Profit/(loss) for the year - - - (625,802) (625,802)
-------------------------------------------- ---------- --------- ----------- --------- ----------
Total comprehensive loss for the year - - - (625,802) (625,802)
-------------------------------------------- ---------- --------- ----------- --------- ----------
Share-based payment - - 3,401 - 3,401
-------------------------------------------- ---------- --------- ----------- --------- ----------
Shares purchased on behalf of Employee
Benefit Trust - - (1,300) - (1,300)
-------------------------------------------- ---------- --------- ----------- --------- ----------
Write down of oil and gas assets - (662,855) - 662,855 -
-------------------------------------------- ---------- --------- ----------- --------- ----------
Balance at 31 December 2020 345,420 - 1,016 (411,076) (64,640)
-------------------------------------------- ---------- --------- ----------- --------- ----------
The attached notes 1 to 30 form part of these Group financial
statements.
Group Statement of Cash Flows
For the year ended 31 December 2020
2020 2019
Notes $'000 $'000
------------------------------------------------------- ----- --------- ---------
CASH FLOW FROM OPERATING ACTIVITIES
------------------------------------------------------- ----- --------- ---------
Cash generated from operations 29 567,830 994,618
------------------------------------------------------- ----- --------- ---------
Cash received/(paid) on sale/(purchase) of financial
instruments 6,226 4,936
------------------------------------------------------- ----- --------- ---------
Decommissioning spend 23 (41,605) (11,131)
------------------------------------------------------- ----- --------- ---------
Income taxes paid (10,366) (26,152)
------------------------------------------------------- ----- --------- ---------
Net cash flows from/(used in) operating activities 522,085 962,271
------------------------------------------------------- ----- --------- ---------
INVESTING ACTIVITIES
------------------------------------------------------- ----- --------- ---------
Purchase of property, plant and equipment (131,376) (234,241)
------------------------------------------------------- ----- --------- ---------
Purchase of intangible oil and gas assets - (3,241)
------------------------------------------------------- ----- --------- ---------
Net cash received on termination of Tanjong Baram risk
service contract 5(d) 51,054 -
------------------------------------------------------- ----- --------- ---------
Repayment of Magnus contingent consideration - Profit
share 22 (41,071) (21,581)
------------------------------------------------------- ----- --------- ---------
Interest received 796 1,225
------------------------------------------------------- ----- --------- ---------
Net cash flows (used in)/from investing activities (120,597) (257,838)
------------------------------------------------------- ----- --------- ---------
FINANCING ACTIVITIES
------------------------------------------------------- ----- --------- ---------
Repayment of loans and borrowings (210,671) (394,025)
------------------------------------------------------- ----- --------- ---------
Repayment of Magnus contingent consideration - Vendor
loan 22 (20,702) (52,669)
------------------------------------------------------- ----- --------- ---------
Shares purchased by Employee Benefit Trust (1,153) -
------------------------------------------------------- ----- --------- ---------
Repayment of obligations under financing leases 24 (123,001) (135,125)
------------------------------------------------------- ----- --------- ---------
Interest paid (42,961) (146,047)
------------------------------------------------------- ----- --------- ---------
Other finance costs paid (2,526) (2,130)
------------------------------------------------------- ----- --------- ---------
Net cash flows from/(used in) financing activities (401,014) (729,996)
------------------------------------------------------- ----- --------- ---------
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS 474 (25,563)
------------------------------------------------------- ----- --------- ---------
Net foreign exchange on cash and cash equivalents 2,482 6,562
------------------------------------------------------- ----- --------- ---------
Cash and cash equivalents at 1 January 218,199 237,200
------------------------------------------------------- ----- --------- ---------
CASH AND CASH EQUIVALENTS AT 31 DECEMBER 221,155 218,199
------------------------------------------------------- ----- --------- ---------
Reconciliation of cash and cash equivalents
------------------------------------------------------- ----- --------- ---------
Cash and cash equivalents per statement of cash flows 14 221,155 218,199
------------------------------------------------------- ----- --------- ---------
Restricted cash 14 1,675 2,257
------------------------------------------------------- ----- --------- ---------
Cash and cash equivalents per balance sheet 222,830 220,456
------------------------------------------------------- ----- --------- ---------
The attached notes 1 to 30 form part of these Group financial
statements.
Notes to the Group Financial Statements
For the year ended 31 December 2020
1. Corporate information
EnQuest PLC ('EnQuest' or the 'Company') is a public company
limited by shares incorporated in the United Kingdom under the
Companies Act and is registered in England and Wales and listed on
the London Stock Exchange and on the Stockholm NASDAQ OMX.
The principal activities of the Company and its subsidiaries
(together the 'Group') are to enhance hydrocarbon recovery and
extend the useful lives of mature and underdeveloped assets and
associated infrastructure in a profitable and responsible
manner.
The Group's financial statements for the year ended 31 December
2020 were authorised for issue in accordance with a resolution of
the Board of Directors on 24 March 2021.
A listing of the Group's companies is contained in note 28 to
these Group financial statements.
2. Summary of significant accounting policies
General information
The preliminary results for the year ended 31 December 2020 have
been extracted from audited accounts which have not yet been
delivered to the Registrar of Companies. The Financial Statements
set out in this announcement do not constitute statutory accounts
for the year ended 31 December 2020 or 31 December 2019. The
financial information for the year ended 31 December 2019 is
derived from the statutory accounts from that year. The report of
the auditors on the statutory accounts for the year ended 31
December 2020 was unqualified and did not contain a statement under
Section 498 of the Companies Act 2006.
Basis of preparation
The consolidated Financial Statements have been prepared in
accordance with International Accounting Standards in conformity
with the requirements of the Companies Act 2006 and International
Financial Reporting Standards adopted pursuant to Regulation (EC)
No 1606/2002 as it applies in the European Union. The accounting
policies which follow set out those policies which apply in
preparing the financial statements for the year ended 31 December
2020.
The Group financial information has been prepared on an
historical cost basis, except for the fair value remeasurement of
certain financial instruments, including derivatives and contingent
consideration, as set out in the accounting policies. The
presentation currency of the Group financial information is US
Dollars ('$') and all values in the Group financial information are
rounded to the nearest thousand ($'000) except where otherwise
stated.
The Group's results on an IFRS basis are shown on the Group
Income Statement as 'Reported in the year', being the sum of our
Business performance results and our Remeasurements and exceptional
items as permitted by IAS 1 (Revised) Presentation of Financial
Statements. Remeasurements and exceptional items are items that
management considers not to be part of underlying business
performance and are disclosed in order to enable shareholders to
understand better and evaluate the Group's reported financial
performance. For further information see note 4.
Going concern
The financial statements have been prepared on the going concern
basis.
The Group closely monitors and manages its funding position and
liquidity risk throughout the year, including monitoring forecast
covenant results, to ensure that it has access to sufficient funds
to meet forecast cash requirements. Cash forecasts are regularly
produced and sensitivities considered for, but not limited to,
changes in crude oil prices (adjusted for hedging undertaken by the
Group), production rates and costs. These forecasts and sensitivity
analyses allow management to mitigate liquidity or covenant
compliance risks in a timely manner. Management has also settled
the required term loan amortisations on or ahead of schedule, with
no further scheduled payments required prior to maturity in October
2021 following the voluntary repayment of the April 2021
amortisation in the fourth quarter of 2020.
The Group continues to monitor actively the impact on operations
from COVID-19 and the health, safety and wellbeing of its employees
is its top priority. The Group remains compliant with UK, Malaysia
and Dubai government and industry policy. The Group has also been
working with a variety of stakeholders, including industry and
medical organisations, to ensure its operational response and
advice to its workforce is appropriate and commensurate with the
prevailing expert advice and level of risk. At the time of
publication of EnQuest's full year results, the Group's day-to-day
operations continue without being materially affected by
COVID-19.
The Group's latest approved business plan underpins management's
base case ('Base Case') and is in line with the Group's production
guidance, assumes a refinancing of the existing Revolving Credit
Facility ('RCF') prior to maturity in October 2021 with a new
facility and uses oil price assumptions of $60/bbl from March to
December 2021 and $58/bbl to the end of the first quarter 2022.
The Base Case has been subjected to stress testing by
considering the impact of the following plausible downside risks
(the 'Downside Case'):
-- 10.0% discount to Base Case prices resulting in Downside Case
prices of $54.0/bbl from March to December 2021 and $52.2/bbl for
2022;
-- Production risking of c.4.0% for 2021; and
-- Incremental decommissioning security of $43 million is met
through letters of credit resulting in a reduction in headroom as
letters of credit are drawings under the RCF.
The Base Case and Downside Case indicate that the Group is able
to operate as a going concern with refinanced borrowing facilities
for 12 months from the date of publication of its full year
results. The Directors have also performed reverse stress testing
on the Base Case, with the breakeven price for liquidity in the
Going Concern period being c.$30/bbl under the assumption the
existing facility is refinanced. In addition, under the Base Case
prices, a minimum size of facility or alternative financing
arrangement of approximately $100 million would be required to
maintain positive headroom should the existing facility not be
refinanced.
The quarterly liquidity covenant in the existing facility (the
'Liquidity Test') requires that the Group shows it has sufficient
funds available to meet all liabilities of the Group when due and
payable for the period commencing on each quarter and ending on the
date falling 12 months after the final maturity date of 1 October
2021. The Liquidity Test will be applied for the quarters ended
March 2021 and June 2021. The Liquidity Test assumptions include a
price deck of the average forward oil price curve, minus a 10%
discount, of 15 consecutive business days starting from
approximately the middle of the previous quarter.
2. Summary of significant accounting policies (continued)
Under these prices, the Group forecasts no breaches in the Base
Case for the Liquidity Test. By applying a discount in excess of
29% (19% in addition to the 10% discount stipulated in the Facility
agreement), the Group would breach this covenant, prior to any
mitigations such as asset divestments or other funding options.
Under such an oil price scenario, the covenant breach would
therefore require a covenant waiver to be obtained. The Directors
are confident that waivers from the facility providers would be
forthcoming. Should circumstances arise that differ from the
Group's projections, the Directors believe that a number of
mitigating actions, including refinancing, asset sales or other
funding options, can be executed successfully in the necessary
timeframe to meet debt repayment obligations as they become due and
in order to maintain liquidity.
Within the going concern period, the RCF expires in October 2021
(see note 18). The Directors are confident that the Group will be
able to refinance the RCF based on the Group's Base Case cash flow
projections.
On 4 February 2021, the Group announced it had signed an
agreement with Suncor Energy UK Limited ('Suncor') to purchase
Suncor's entire 26.69% non-operated equity interest in the Golden
Eagle area for an initial consideration of $325 million, excluded
from the Base Case. The Group also advised plans to finance the
transaction through the combination of a new secured debt facility,
an equity raise, and the interim period post-tax cash flows
generated from the economic date of 1 January 2021 to transaction
completion.
A final term sheet has been agreed following bilateral
discussions with DNB and BNP (lead and co-technical banks) and has
been approved by their respective credit committees. DNB and BNP
have also received credit committee approval for material
commitments to the new financing. The Directors are confident they
will be able to complete the new financing given the feedback it
has had from both current lenders and also potential new lenders.
In the unlikely event the Suncor acquisition does not complete, the
Directors are also confident they will be able to negotiate a new
facility based on the Group's existing asset base or alternative
financing arrangements such as a prepayment facility would be
available to bridge any shortfall.
Whilst securing lenders commitment to the new facility remains
on track, the new facility has not been signed at the time of
publication of the Group's results. Although the Directors are
confident that the new facility will be executed, the facility has
not yet been signed; in these circumstances they have to conclude
that this represents a material uncertainty that may cast
significant doubt upon the Group's ability to continue as a going
concern, such that it may not be able to realise its assets and
discharge its liabilities in the normal course of business.
Notwithstanding the material uncertainty as described above,
after making appropriate enquiries and assessing the progress
against the forecast, projections and the status of the mitigating
actions referred to above, and in particular the advanced state of
the proposed refinancing agreement, the Directors have a reasonable
expectation that the Group will continue in operation and meet its
commitments as they fall due over the going concern period.
Accordingly, the Directors continue to adopt the going concern
basis in preparing these financial statements.
New standards and interpretations
The following new standards became applicable for the current
reporting period. No material impact was recognised upon
application:
-- Amendments to References to Conceptual Framework in IFRS Standards
-- Interest Rate Benchmark Reform (Amendments to IFRS 9, IAS 39, IFRS 7)
-- Definition of a Business (Amendments to IFRS 3)
-- Definition of Material (Amendments to IAS 1 and IAS 8)
-- Impact of the initial application of COVID-19-Related Rent
Concessions (Amendment to IFRS 16)
Standards issued but not yet effective
At the date of authorisation of these financial statements, the
Group has not applied the following new and revised IFRS Standards
that have been issued but are not yet effective:
IFRS 17 Insurance Contracts
------------------------------- ---------------------------------------------------------
IFRS 10 and IAS 28 (amendments) Sale or Contribution of Assets between an Investor
and its Associate or Joint Venture
------------------------------- ---------------------------------------------------------
Amendments to IAS 1 Classification of Liabilities as Current or Non-current
------------------------------- ---------------------------------------------------------
Amendments to IFRS 3 Reference to the Conceptual Framework
------------------------------- ---------------------------------------------------------
Amendments to IAS 16 Property, Plant and Equipment-Proceeds before Intended
Use
------------------------------- ---------------------------------------------------------
Amendments to IAS 37 Onerous Contracts - Cost of Fulfilling a Contract
------------------------------- ---------------------------------------------------------
Annual Improvements to Amendments to IFRS 1 First-time Adoption of International
IFRS Standards 2018-2020 Financial Reporting Standards, IFRS 9 Financial
Cycle Instruments, IFRS 16 Leases, and IAS 41 Agriculture
The Directors do not expect that the adoption of the Standards
listed above will have a material impact on the financial
statements of the Group in future periods.
Basis of consolidation
The consolidated financial statements incorporate the financial
statements of EnQuest PLC and entities controlled by the Company
(its subsidiaries) made up to 31 December each year. Control is
achieved when the Company:
-- has power over the investee;
-- is exposed, or has rights, to variable returns from its involvement with the investee; and
-- has the ability to use its power to affect its returns.
The Company reassesses whether or not it controls an investee if
facts and circumstances indicate that there are changes to one or
more of the three elements of control listed above. Consolidation
of a subsidiary begins when the Company obtains control over the
subsidiary and ceases when the Company loses control of the
subsidiary. Specifically, the results of subsidiaries acquired or
disposed of during the year are included in profit or loss from the
date the Company gains control until the date when the Company
ceases to control the subsidiary.
Where necessary, adjustments are made to the financial
statements of subsidiaries to bring the accounting policies used
into line with the Group's accounting policies. All intra-Group
assets and liabilities, equity, income, expenses and cash flows
relating to transactions between the members of the Group are
eliminated on consolidation.
2. Summary of significant accounting policies (continued)
Joint arrangements
Oil and gas operations are usually conducted by the Group as
co-licensees in unincorporated joint operations with other
companies. Joint control is the contractually agreed sharing of
control of an arrangement, which exists only when decisions about
the relevant activities require the consent of the relevant parties
sharing control. The joint operating agreement is the underlying
contractual framework to the joint arrangement, which is
historically referred to as the joint venture ('JV'). The Annual
Report and Accounts therefore refers to 'joint ventures' as
standard terms used in the oil and gas industry, which is used
interchangeably with joint operations.
Most of the Group's activities are conducted through joint
operations, whereby the parties that have joint control of the
arrangement have the rights to the assets, and obligations for the
liabilities relating to the arrangement. The Group reports its
interests in joint operations using proportionate consolidation -
the Group's share of the production, assets, liabilities, income
and expenses of the joint operation are combined with the
equivalent items in the consolidated financial statements on a
line-by-line basis. During 2020, the Group did not have any
material interests in joint ventures or in associates. During 2020,
the Group did not have any material interests in joint ventures or
in associates as defined in IAS 28.
Foreign currencies
Items included in the financial statements of each of the
Group's entities are measured using the currency of the primary
economic environment in which the entity operates ('functional
currency'). The Group's financial statements are presented in US
Dollars, the currency which the Group has elected to use as its
presentation currency.
In the financial statements of the Company and its individual
subsidiaries, transactions in currencies other than a company's
functional currency are recorded at the prevailing rate of exchange
on the date of the transaction. At the year end, monetary assets
and liabilities denominated in foreign currencies are retranslated
at the rates of exchange prevailing at the balance sheet date.
Non-monetary assets and liabilities that are measured at historical
cost in a foreign currency are translated using the rate of
exchange at the dates of the initial transactions. Non-monetary
assets and liabilities measured at fair value in a foreign currency
are translated using the rate of exchange at the date the fair
value was determined. All foreign exchange gains and losses are
taken to profit and loss in the Group income statement.
Critical accounting judgements
The Group assesses critical accounting judgements annually. The
following are the critical judgements, apart from those involving
estimations which are dealt with in the policy 'Key sources of
estimation uncertainty' below, that the Directors have made in the
process of applying the Group's accounting policies, which have the
most significant effect on the amounts recognised in the financial
statements.
Oil and gas reserves
The business of the Group is to enhance hydrocarbon recovery and
extend the useful lives of mature and underdeveloped assets and
associated infrastructure in a profitable and responsible manner.
The process in determining the estimates of oil and gas reserves
requires critical judgement. Factors such as the availability of
geological and engineering data, reservoir performance data,
acquisition and divestment activity and drilling of new wells all
impact on the determination of the Group's estimates of its oil and
gas reserves and result in different future production profiles
affecting prospectively the discounted cash flows used in
impairment testing and the calculation of contingent consideration,
the anticipated date of decommissioning and the depletion charges
in accordance with the unit of production method, as well as the
going concern assessment.
The Group uses proven and probable ('2P') reserves (see page 27)
as the basis for calculations of expected future cash flows from
underlying assets because this represents the reserves management
intend to develop. Third-party audits of EnQuest's reserves and
resources are conducted annually.
Key sources of estimation uncertainty
The key sources of estimation uncertainty concerning the future,
and other major sources of estimation uncertainty at the end of the
reporting period, that have a significant risk of resulting in a
material adjustment to the carrying amounts of assets and
liabilities within the next financial year, are discussed
below:
Future oil prices
Future oil prices are a key driver of estimation affecting the
recoverable amount of oil and gas assets and are used in the
calculation of future cash flows which impact contingent
consideration and decommissioning. Oil and gas price assumptions
are reviewed and, where necessary, adjusted on a periodic basis.
The estimates take into account existing prices impacted by changes
in supply and demand as a result of COVID-19, historical trends and
variability and other macroeconomic factors. Significant
uncertainty exists regarding future long term oil and gas prices
with factors such as the energy transition to a lower carbon
economy being considered in the updated assumptions. Review
includes benchmarking and analysis against forward curves from
available market data and other third-party forecasts, as well as
review and challenge by the Audit Committee.
A reduction or increase in future oil prices of 10%, based on
the approximate volatility of historical oil prices, are considered
to be reasonably possible changes for the purposes of sensitivity
analysis and reflects the inherent uncertainty of forecasting
future oil price and the uncertainty of the impact of the energy
transition. The impact of this sensitivity is disclosed in notes 7,
10 and 22.
As a result of the decline in global oil demand resulting from
the COVID-19 pandemic, and the potential for weaker demand to
continue as the energy transition to a lower-carbon economy
continues, the Group revised its price assumptions for impairment
testing. Oil price assumptions based on an internal view of forward
curve prices at 31 December 2020 are $47/bbl (2021), $55/bbl
(2022), $60/bbl (2023) and $60/bbl real thereafter, inflated at
2.0% per annum from 2024 (2019: $63.0/bbl (2020), $65.0/bbl (2021),
$67.0/bbl (2022) and $70.0/bbl real thereafter , inflated at 2% per
annum from 2024). Discounts or premiums are applied to price
assumptions based on the characteristics of the oil produced and of
the terms of the relevant sales contracts.
Impairment testing of oil and gas assets and goodwill and
valuation of Magnus contingent consideration
Determination of whether oil and gas assets or goodwill have
suffered any impairment requires an estimation of the fair value
less costs to dispose of the cash generating units ('CGU') to which
oil and gas assets and goodwill have been allocated. The
calculation requires the entity to estimate the future cash flows
expected to arise from the CGU using the same discounted cash flow
model used to assess the impairment of assets, which comprises
asset-by-asset life of field projections using management's best
estimates of oil and gas reserves, future oil prices and other
Level 3 inputs (based on the IFRS 13 fair value hierarchy).
Determination of the Magnus contingent consideration valuation
requires an estimation of the fair value less costs to dispose of
the cash generating unit, the Magnus asset. The calculation
requires the entity to estimate the future cash flows expected to
arise from the CGU using the same discounted cash flow model used
to assess the impairment of assets.
2. Summary of significant accounting policies (continued)
The calculation of the discounted cash flow models are based on
the following:
-- Oil prices (see above);
-- Oil and gas reserves (see above);
-- Production profiles based on internal life of field estimates
including assumptions on performance of assets;
-- Related life of field opex, capex and decommissioning costs
derived from the Group's business plan adjusted for changes in
timing based on the production profiles used as above; and
-- Discount rates driven by a market participant's weighted average cost of capital.
The discount rate applied to fair value less costs of disposal
calculations reflects management's estimate of a market participant
weighted average cost of capital ('WACC'). The discount rate is a
post-tax discount rate and is reviewed and, where necessary,
adjusted on an annual basis. The post-tax discount rate applied to
the Group's post-tax cash flow projections was 10.0% (2019: 10.0%).
A reduction or increase in the discount rate of 1.0% are considered
to be reasonably possible changes for the estimated purposes of
sensitivity analysis. Sensitivities related to the discount rates
are disclosed in note 10.
Decommissioning provision
Provisions for decommissioning and restoration costs are
estimates based on current legal and constructive requirements,
current technology and price levels for the removal of facilities
and plugging and abandoning of wells. These parameters are based on
information and estimates deemed to be appropriate by the Group at
the current time. The eventual decommissioning and restoration
costs are uncertain and estimates can vary in response to many
factors, including changes to relevant legal requirements,
estimates of the extent and costs of decommissioning activities,
the emergence of new restoration techniques or experience at other
production sites, cost increases as compared to the inflation
rates, and changes in discount rates. The expected timing, extent
and amount of expenditure may also change, for example, in response
to changes in oil and gas reserves or changes in laws and
regulations or their interpretation. Therefore, significant
estimates and assumptions are made in determining the provision for
decommissioning. As a result, there could be significant
adjustments to the provisions established which would affect future
financial results. Due to the significant estimates and
assumptions, the carrying amounts of decommissioning provisions are
reviewed on a regular basis.
The present value of the provision for decommissioning is
calculated using amounts discounted over the useful economic life
of the assets. The Group applies an annual inflation rate of 2.0%
(2019: 2.0%) and an annual discount rate of 2.0% to the UK ('North
Sea') assets and 3.0% to the Malaysian assets (2019: 2.0% for both
the UK and Malaysia). A reduction or increase in the discount rate
of 0.5% are considered to be reasonably possible changes for the
estimated purposes of sensitivity analysis. Sensitivities related
to the discount rates are disclosed in note 23.
Deferred taxation
The Group recognises deferred tax assets on unused tax losses
where it is probable that future taxable profits will be available
for utilisation. This requires management to make assumptions and
estimates relating to future oil prices and oil and gas reserves
(as discussed above) and the estimated future costs, to assess the
amount of deferred tax that can be recognised.
3. Segment information
Management has considered the requirements of IFRS 8 Operating
Segments in regard to the determination of operating segments and
concluded that the Group has two significant operating segments:
the North Sea and Malaysia. Operations are managed by location and
all information is presented per geographical segment. The
information reported to the Chief Operating Decision Maker does not
include an analysis of assets and liabilities, and accordingly this
information is not presented.
Adjustments
Year ended 31 December 2020 Total and
North All other eliminations
$'000 Sea Malaysia segments segments (i) Consolidated
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Revenue:
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Revenue from contracts with customers 792,508 62,917 - 855,425 - 855,425
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Other income 7,224 - 280 7,504 2,719 10,223
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Total revenue 799,732 62,917 280 862,929 2,719 865,648
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Income/(expenses) line items:
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Depreciation and depletion (430,169) (15,638) (56) (445,863) - (445,863)
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Net impairment (charge)/reversal
to oil and gas assets (422,495) - - (422,495) - (422,495)
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Segment profit/(loss) (ii) (318,952) 4,153 3,372 (311,427) 1,358 (310,069)
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Other disclosures:
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Capital expenditure(iii) 81,504 2,144 - 83,648 - 83,648
-------------------------------------- --------- -------- --------- --------- -------------- ------------
Adjustments
Year ended 31 December 2019 Total and
North All other
$'000 Sea Malaysia segments segments eliminations(i) Consolidated
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Revenue:
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Revenue from contracts with customers 1,530,343 145,749 - 1,676,092 - 1,676,092
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Other income 10,500 - 486 10,986 (40,619) (29,633)
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Total revenue 1,540,843 145,749 486 1,687,078 (40,619) 1,646,459
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Income/(expenses) line items:
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Depreciation and depletion (518,785) (14,490) (77) (533,352) - (533,352)
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Net impairment (charge)/reversal
to oil and gas assets (812,448) - - (812,448) - (812,448)
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Impairment reversal of investments (20) - - (20) - (20)
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Exploration write offs and impairments (150) - - (150) - (150)
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Segment profit/(loss) (ii) (470,351) 49,429 (4,142) (425,064) (42,704) (467,768)
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Other disclosures:
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
Capital expenditure(iii) 164,818 15,837 - 180,655 - 180,655
--------------------------------------- ---------- -------- --------- ---------- ---------------- ------------
(i) Finance income and costs and gains and losses on derivatives
are not allocated to individual segments as the underlying
instruments are managed on a Group basis
(ii) Inter-segment revenues are eliminated on consolidation. All
other adjustments are part of the reconciliations presented further
below
(iii) Capital expenditure consists of property, plant and
equipment and intangible assets, including assets from the
acquisition of subsidiaries
Reconciliation of profit/(loss):
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
---------------------------------------------------- ------------ ------------
Segment profit/(loss) (311,427) (425,064)
---------------------------------------------------- ------------ ------------
Finance income 1,171 2,416
---------------------------------------------------- ------------ ------------
Finance expense (257,077) (263,761)
---------------------------------------------------- ------------ ------------
Gain/(loss) on oil and foreign exchange derivatives 1,358 (42,704)
---------------------------------------------------- ------------ ------------
Profit/(loss) before tax (565,975) (729,113)
---------------------------------------------------- ------------ ------------
Revenue from four customers relating to the North Sea operating
segment each exceeds 10% of the Group's consolidated revenue
arising from sales of crude oil, with amounts of $188.9 million,
$143.4 million, $113.1 million and $84.9 million per each single
customer (2019: Three customers; $307.1 million, $266.1 million and
$211.0 million per each single customer).
4. Remeasurements and exceptional items
Accounting policy
As permitted by IAS 1 (Revised) Presentation of Financial
Statements, certain items of income or expense which are material
are presented separately. Additional line items, headings,
sub-totals and disclosures of nature and amount are presented to
provide relevant understanding of the Group's financial
performance.
Remeasurements and exceptional items are items that management
considers not to be part of underlying business performance and are
disclosed in order to enable shareholders to understand better and
evaluate the Group's reported financial performance. The items that
the Group separately presents as exceptional on the face of the
Group income statement are those material items of income and
expense which, because of the nature or expected infrequency of the
events giving rise to them, merit separate presentation to allow
shareholders to understand better the elements of financial
performance in the year, so as to facilitate comparison with prior
periods and to better assess trends in financial performance.
Remeasurements relate to those items which are remeasured on a
periodic basis and are applied consistently year-on-year. If an
item is assessed as a remeasurement or exceptional item, then
subsequent accounting to completion of the item is also taken
through remeasurement and exceptional items. Management has
exercised judgement in assessing the relevant material items
disclosed as exceptional.
The following items are classified as remeasurements and
exceptional items ('exceptional'):
-- Unrealised mark-to-market changes in the remeasurement of
open derivative contracts at each period end are recognised within
remeasurements, with the recycling of realised amounts from
remeasurements into Business performance income when a derivative
instrument matures;
-- Impairments on assets, including other non-routine
write-offs/write-downs where deemed material, are remeasurements
and are deemed to be exceptional in nature;
-- Fair value accounting arising in relation to business
combinations is deemed as exceptional in nature, as these
transactions do not relate to the principal activities and
day-to-day Business performance of the Group. The subsequent
remeasurement of contingent assets and liabilities arising on
acquisitions, including contingent consideration, are presented
within remeasurements and are presented consistently year-on-year;
and
Other items that arise from time to time that are reviewed by
management as non-Business performance and are disclosed further
below.
Impairments
Year ended 31 December 2020 Fair value and
remeasurement write Other
$'000 (i) offs (ii) (iii) Total
-------------------------------------------- --------------- ----------- -------- ---------
Revenue and other operating income 8,778 - - 8,778
-------------------------------------------- --------------- ----------- -------- ---------
Cost of sales (1,932) - (11,694) (13,626)
-------------------------------------------- --------------- ----------- -------- ---------
Net impairment (charge)/reversal on oil and
gas assets - (422,495) - (422,495)
-------------------------------------------- -------- ---------
Other income 138,249 - - 138,249
-------------------------------------------- -------- ---------
Other expense - - (956) (956)
-------------------------------------------- --------------- ----------- -------- ---------
Finance costs - - (77,259) (77,259)
-------------------------------------------- --------------- ----------- -------- ---------
145,095 (422,495) (89,909) (367,309)
-------------------------------------------- --------------- ----------- -------- ---------
Tax on items above (57,687) 163,267 33,175 138,755
-------------------------------------------- --------------- ----------- -------- ---------
De-recognition of undiscounted deferred tax
asset(IV) - (371,061) - (371,061)
-------------------------------------------- --------------- ----------- -------- ---------
87,408 (630,289) (56,734) (599,615)
-------------------------------------------- --------------- ----------- -------- ---------
Impairments
Year ended 31 December 2019 Fair value and
write
$'000 remeasurement(i) offs(ii) Other(iii) Total
-------------------------------------------- ----------------- ----------- ---------- ---------
Revenue and other operating income (65,375) - - (65,375)
-------------------------------------------- ----------------- ----------- ---------- ---------
Cost of sales (378) - - (378)
-------------------------------------------- ----------------- ----------- ---------- ---------
Net impairment (charge)/reversal on oil and
gas assets - (812,448) - (812,448)
-------------------------------------------- ----------------- ----------- ---------- ---------
Other expenses (15,520) (170) (16,045) (31,735)
-------------------------------------------- ----------------- ----------- ---------- ---------
Finance costs - - (57,165) (57,165)
-------------------------------------------- ----------------- ----------- ---------- ---------
(81,273) (812,618) (73,210) (967,101)
-------------------------------------------- ----------------- ----------- ---------- ---------
Tax on items above 31,735 250,235 21,490 303,460
-------------------------------------------- ----------------- ----------- ---------- ---------
(49,538) (562,383) (51,720) (663,641)
-------------------------------------------- ----------------- ----------- ---------- ---------
(i) Fair value remeasurements include unrealised mark-to-market
movements on derivative contracts and other financial instruments
and the impact of recycled realised gains and losses out of
'Remeasurements and exceptional items' and into Business
performance profit or loss of $6.8 million. Other income relates to
the fair value remeasurement of contingent consideration relating
to the acquisition of Magnus and associated infrastructure of
$138.2 million (note 22) (2019: other loss of $15.5 million)
(ii) Impairments and write offs include an impairment of
tangible oil and gas assets totalling $422.5 million (note 10)
(2019: impairment of $637.5 million plus other related
intangibles)
(iii) Other items mainly relate to unwinding of discount on
contingent consideration on the 75% acquisition of Magnus and
associated infrastructure of $77.3 million (note 22) (2019: $57.2
million), provision for the PM8/Seligi riser repair $5.9 million
(note 23), loss on decrecognition of assets related to the Seligi
riser detachment $1.0m (note 5(b)) and the redundancy costs in
relation to the Group's transformation programme of $5.8 million
(2019: the cost for settlement of the historical KUFPEC claim of
$15.6 million)
(iv) Non-cash partial de-recognition of undiscounted deferred
tax assets given the Group's lower oil price assumptions
5. Revenue and expenses
(a) Revenue and other operating income
Accounting policy
Revenue from contracts with customers
The Group generates revenue through the sale of crude oil, gas
and condensate to third parties, and through the provision of
infrastructure to its customers for tariff income. Revenue from
contracts with customers is recognised when control of the goods or
services is transferred to the customer at an amount that reflects
the consideration to which the Group expects to be entitled to in
exchange for those goods or services. The Group has concluded that
it is the principal in its revenue arrangements because it
typically controls the goods or services before transferring them
to the customer. The normal credit term is 30 days or less upon
performance of the obligation.
Sale of crude oil, gas and condensate
The Group sells crude oil, gas and condensate directly to
customers. The sale represents a single performance obligation,
being the sale of barrels equivalent to the customer on taking
physical possession or on delivery of the commodity into an
infrastructure. At this point the title passes to the customer and
revenue is recognised. The Group principally satisfies its
performance obligations at a point in time; the amounts of revenue
recognised relating to performance obligations satisfied over time
are not significant. Transaction prices are referenced to quoted
prices, plus or minus an agreed discount rate, if applicable.
Tariff revenue for the use of Group infrastructure
Tariffs are charged to customers for the use of infrastructure
owned by the Group. The revenue represents the performance of an
obligation for the use of Group assets over the life of the
contract. The use of the assets is not separable as they are
interdependent in order to fulfil the contract and no one item of
infrastructure can be individually isolated. Revenue is recognised
as the performance obligations are satisfied over the period of the
contract, generally a period of 12 months or less, on a monthly
basis based on throughput at the agreed contracted rates.
Other operating income
Other revenue includes rental income, which is recognised to the
extent that it is probable economic benefits will flow to the Group
and the revenue can be reliably measured.
The Group enters into oil derivative trading transactions which
can be settled net in cash. Accordingly, any gains or losses are
not considered to constitute revenue from contracts with customers
in accordance with the requirements of IFRS 15, and are included
within other operating income (see note 19).
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
---------------------------------------------------------- ------------ ------------
Revenue from contracts with customers:
---------------------------------------------------------- ------------ ------------
Revenue from crude oil sales 779,865 1,548,177
---------------------------------------------------------- ------------ ------------
Revenue from gas and condensate sales(i) 60,486 120,242
---------------------------------------------------------- ------------ ------------
Tariff revenue 15,074 7,673
---------------------------------------------------------- ------------ ------------
Total revenue from contracts with customers 855,425 1,676,092
---------------------------------------------------------- ------------ ------------
Rental income 5,706 7,082
---------------------------------------------------------- ------------ ------------
Realised (losses)/gains on oil derivative contracts (see
note 19) (6,059) 24,756
---------------------------------------------------------- ------------ ------------
Other 1,798 3,904
---------------------------------------------------------- ------------ ------------
Business performance revenue and other operating income 856,870 1,711,834
---------------------------------------------------------- ------------ ------------
Unrealised (losses)/gains on oil derivative contracts(ii)
(see note 19) 8,778 (65,375)
---------------------------------------------------------- ------------ ------------
Total revenue and other operating income 865,648 1,646,459
---------------------------------------------------------- ------------ ------------
(i) Includes onward sale of third-party gas purchases not
required for injection activities at Magnus
(ii) Unrealised gains and losses on oil derivative contracts are
disclosed as fair value remeasurement items in the income statement
(see note 4)
Disaggregation of revenue from contracts with customers
Year ended 31 Year ended 31
December 2020 December 2019
$'000 $'000
-------------------------------------------- ------------------ --------------------
North North
Sea Malaysia Sea Malaysia
-------------------------------------------- -------- -------- ---------- --------
Revenue from contracts with customers:
-------------------------------------------- -------- -------- ---------- --------
Revenue from crude oil sales 719,504 60,361 1,405,956 142,221
-------------------------------------------- -------- -------- ---------- --------
Revenue from gas and condensate sales 57,930 2,556 116,714 3,528
-------------------------------------------- -------- -------- ---------- --------
Tariff revenue 15,074 - 7,673 -
-------------------------------------------- -------- -------- ---------- --------
Total revenue from contracts with customers 792,508 62,917 1,530,343 145,749
-------------------------------------------- -------- -------- ---------- --------
5. Revenue and expenses (continued)
(b) Cost of sales
Accounting policy
Production imbalances, movements in under/over-lift and
movements in inventory are included in cost of sales. The over-lift
liability is recorded at the cost of the production imbalance to
represent a provision for production costs attributable to the
volumes sold in excess of entitlement. The under-lift asset is
recorded at the lower of cost and net realisable value, consistent
with IAS2, to represent a right to additional physical inventory.
An under-lift of production from a field is included in current
receivables and an over-lift of production from a field is included
in current liabilities.
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
------------------------------------------------------------------ ------------ ------------
Production costs 265,529 441,624
------------------------------------------------------------------ ------------ ------------
Tariff and transportation expenses 63,685 74,782
------------------------------------------------------------------ ------------ ------------
Realised loss/(gain) on derivative contracts related to operating
costs (see note 19) (572) 1,707
------------------------------------------------------------------ ------------ ------------
Change in lifting position (31,508) 96,886
------------------------------------------------------------------ ------------ ------------
Crude oil inventory movement (3,293) 5,967
------------------------------------------------------------------ ------------ ------------
Depletion of oil and gas assets(i) 438,247 525,145
------------------------------------------------------------------ ------------ ------------
Other cost of operations(ii) 53,367 97,459
------------------------------------------------------------------ ------------ ------------
Business performance cost of sales 785,455 1,243,570
------------------------------------------------------------------ ------------ ------------
Unrealised (gains)/losses on derivative contracts related
to operating costs(iii) (see note 19) 1,932 378
------------------------------------------------------------------ ------------ ------------
Redundancy costs related to the transformation programme 5,792 -
------------------------------------------------------------------ ------------ ------------
PM8/Seligi riser repair provision (see note 23) 5,902 -
------------------------------------------------------------------ ------------ ------------
Total cost of sales 799,081 1,243,948
------------------------------------------------------------------ ------------ ------------
(i) Includes $68.5 million Kraken FPSO right-of-use asset
depreciation charge and $10.5 million of vessels within
right-of-use assets depreciation charge
(ii) Includes $24.7 million of inventory provisions and also
includes purchases of third-party gas not required for injection
activities at Magnus which is sold on
(iii) Unrealised gains and losses on derivative contracts are
disclosed as fair value remeasurement in the income statement (see
note 4)
(c) General and administration expenses
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
----------------------------------------------------------- ------------ ------------
Staff costs (see note 5(f)) 85,813 90,764
----------------------------------------------------------- ------------ ------------
Depreciation(i) 7,616 8,207
----------------------------------------------------------- ------------ ------------
Other general and administration costs 21,831 23,094
----------------------------------------------------------- ------------ ------------
Recharge of costs to operations and joint venture partners (109,155) (114,404)
----------------------------------------------------------- ------------ ------------
Total general and administration expenses 6,105 7,661
----------------------------------------------------------- ------------ ------------
(i) Includes $3.7 million right-of-use assets depreciation
charge on buildings
(d) Other income
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
----------------------------------------------------------- ------------ ------------
Gain on termination of Tanjong Baram risk service contract 10,209 -
----------------------------------------------------------- ------------ ------------
Other income 6,095 3,446
----------------------------------------------------------- ------------ ------------
Business performance other income 16,304 3,446
----------------------------------------------------------- ------------ ------------
Fair value changes in contingent consideration (see note
22) 138,249 -
----------------------------------------------------------- ------------ ------------
Total other income 154,553 3,446
----------------------------------------------------------- ------------ ------------
On 3 March 2020, the Group terminated the Tanjong Baram small
field risk service contract with Petronas. Following the
termination, the Group received three instalments from Petronas for
the reimbursement of net outstanding capital expenditure of $51.1
million. The Group received $72.9 million from Petronas in 2020, of
which $21.8 million was received on behalf of the non-operating
partner and immediately transferred. The amount has been presented
net in the statement of cash flows to represent the substance of
the transaction. On termination, the Tanjong Baram assets were
carried at c.$40 million resulting in the $10.2 million gain (see
note 10).
(e) Other expenses
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
------------------------------------------------------------ ------------ ------------
Net foreign exchange losses 4,625 16,427
------------------------------------------------------------ ------------ ------------
Change in decommissioning provisions 83,199 -
------------------------------------------------------------ ------------ ------------
Change in Thistle decommissioning provisions (note 23) 11,998 -
------------------------------------------------------------ ------------ ------------
Other 1,811 5,454
------------------------------------------------------------ ------------ ------------
Business performance other expenses 101,633 21,881
------------------------------------------------------------ ------------ ------------
Loss on derecognition of assets related to the Seligi riser
detachment 956 -
------------------------------------------------------------ ------------ ------------
Fair value changes in contingent consideration (see note
22) - 15,520
------------------------------------------------------------ ------------ ------------
Settlement provision (see note 23) - 15,630
------------------------------------------------------------ ------------ ------------
Other - 585
------------------------------------------------------------ ------------ ------------
Total other expenses 102,589 53,616
------------------------------------------------------------ ------------ ------------
5. Revenue and expenses (continued)
(f) Staff costs
Accounting policy
Short-term employee benefits such as salaries, social premiums
and holiday pay, are expensed when incurred.
The Group's pension obligations consist of defined contribution
plans. The Group pays fixed contributions with no further payment
obligations once the contributions have been paid. The amount
charged to the Group income statement in respect of pension costs
reflects the contributions payable in the year. Differences between
contributions payable during the year and contributions actually
paid are shown as either accrued liabilities or prepaid assets in
the balance sheet.
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
------------------------------------------------------- ------------ ------------
Wages and salaries 85,913 88,951
------------------------------------------------------- ------------ ------------
Social security costs 9,118 9,511
------------------------------------------------------- ------------ ------------
Defined contribution pension costs 6,871 7,115
------------------------------------------------------- ------------ ------------
Expense of share-based payments (see note 21) 3,401 5,886
------------------------------------------------------- ------------ ------------
Other staff costs 12,781 12,609
------------------------------------------------------- ------------ ------------
Total employee costs 118,084 124,072
------------------------------------------------------- ------------ ------------
Contractor costs 39,371 50,975
------------------------------------------------------- ------------ ------------
Total staff costs 157,455 175,047
------------------------------------------------------- ------------ ------------
General and administration staff costs (see note 5(c)) 85,813 90,764
------------------------------------------------------- ------------ ------------
Non-general and administration costs 71,642 84,283
------------------------------------------------------- ------------ ------------
Total staff costs 157,455 175,047
------------------------------------------------------- ------------ ------------
In 2020 the Group changed its methodology for disclosing staff
costs and therefore the 2019 allocation of staff costs has been
restated to ensure consistency.
The average number of persons, excluding contractors, employed
by the Group during the year was 885, with 383 in the general and
administration staff costs and 502 directly attributable to assets
(2018: 958 of which 407 in general and administration and 551
directly attributable to assets).
Compensation of key management personnel is disclosed in note
26.
(g) Auditor's remuneration
Following a comparative tender process held during 2019,
Deloitte LLP ('Deloitte') was appointed as auditor replacing Ernst
and Young LLP ('EY'). The following amounts for the year ended 31
December 2020 were payable by the Group to Deloitte and for the
year ended 31 December 2019 to EY:
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
----------------------------------------------------------- ------------ ------------
Fees payable to the Company's auditor for the audit of the
parent company and Group financial statements 649 682
----------------------------------------------------------- ------------ ------------
The audit of the Company's subsidiaries 178 176
----------------------------------------------------------- ------------ ------------
Total audit 827 858
----------------------------------------------------------- ------------ ------------
Audit related assurance services(i) 180 136
----------------------------------------------------------- ------------ ------------
Total audit and audit related assurance services 1,007 994
----------------------------------------------------------- ------------ ------------
Tax services 10 12
----------------------------------------------------------- ------------ ------------
Total auditor's remuneration 1,017 1,006
----------------------------------------------------------- ------------ ------------
(i) Audit-related assurance services include the review of the
Group's interim results and assurance work in respect of the
Group's joint venture activities.
6. Finance costs/income
Accounting policy
Borrowing costs are recognised as interest payable within
finance costs in accordance with the effective interest method.
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
------------------------------------------------------------ ------------ ------------
Finance costs:
------------------------------------------------------------ ------------ ------------
Loan interest payable 32,791 67,749
------------------------------------------------------------ ------------ ------------
Bond interest payable 73,476 62,694
------------------------------------------------------------ ------------ ------------
Unwinding of discount on decommissioning provisions (see
note 23) 14,512 13,410
------------------------------------------------------------ ------------ ------------
Unwinding of discount on Thistle decommissioning provisions
(see note 23) 796 671
------------------------------------------------------------ ------------ ------------
Finance charges payable under leases 50,851 55,686
------------------------------------------------------------ ------------ ------------
Amortisation of finance fees on loans and bonds 5,417 5,727
------------------------------------------------------------ ------------ ------------
Other financial expenses 1,975 2,055
------------------------------------------------------------ ------------ ------------
179,818 207,992
------------------------------------------------------------ ------------ ------------
Less: amounts capitalised to the cost of qualifying assets - (1,396)
------------------------------------------------------------ ------------ ------------
Business performance finance expenses 179,818 206,596
------------------------------------------------------------ ------------ ------------
Finance costs on contingent consideration (see note 22) 77,259 57,165
------------------------------------------------------------ ------------ ------------
Total finance costs 257,077 263,761
------------------------------------------------------------ ------------ ------------
Finance income:
------------------------------------------------------------ ------------ ------------
Bank interest receivable 896 1,511
------------------------------------------------------------ ------------ ------------
Unwinding of discount on financial asset (see note 19(e)) 275 905
------------------------------------------------------------ ------------ ------------
Total finance income 1,171 2,416
------------------------------------------------------------ ------------ ------------
7. Income tax
(a) Income tax
Accounting policy
Current tax assets and liabilities are measured at the amount
expected to be recovered from or paid to the taxation authorities,
based on tax rates and laws that are enacted or substantively
enacted by the balance sheet date.
The Group's operations are subject to a number of specific tax
rules which apply to exploration, development and production. In
addition, the tax provision is prepared before the relevant
companies have filed their tax returns with the relevant tax
authorities and, significantly, before these have been agreed. As a
result of these factors, the tax provision process necessarily
involves the use of a number of estimates and judgements including
those required in calculating the effective tax rate. In
considering the tax on exceptional items, the Group applies the
appropriate statutory tax rate to each item to calculate the
relevant tax charge on exceptional items.
Deferred tax is provided in full on temporary differences
arising between the tax bases of assets and liabilities and their
carrying amounts in the Group financial statements. However,
deferred tax is not accounted for if it arises from initial
recognition of an asset or liability in a transaction other than a
business combination that at the time of the transaction affects
neither accounting nor taxable profit or loss. Deferred tax is
measured on an undiscounted basis using tax rates (and laws) that
have been enacted or substantively enacted by the balance sheet
date and are expected to apply when the related deferred tax asset
is realised or the deferred tax liability is settled. Deferred tax
assets are recognised to the extent that it is probable that future
taxable profits will be available against which the temporary
differences can be utilised.
Deferred tax liabilities are recognised for taxable temporary
differences arising on investments in subsidiaries, except where
the Group is able to control the reversal of the temporary
difference and it is probable that the temporary difference will
not reverse in the foreseeable future.
The carrying amount of deferred income tax assets is reviewed at
each balance sheet date. Deferred income tax assets and liabilities
are offset only if a legal right exists to offset current tax
assets against current tax liabilities, the deferred income taxes
relate to the same taxation authority and that authority permits
the Group to make a single net payment.
Production taxes
In addition to corporate income taxes, the Group's financial
statements also include and disclose production taxes on net income
determined from oil and gas production.
Production tax relates to Petroleum Revenue Tax ('PRT') within
the UK and is accounted for under IAS 12 Income Taxes since it has
the characteristics of an income tax as it is imposed under
government authority and the amount payable is based on taxable
profits of the relevant fields. Current and deferred PRT is
provided on the same basis as described above for income taxes.
Investment allowance
The UK taxation regime provides for a reduction in ring-fence
supplementary charge tax where investment in new or existing UK
assets qualify for a relief known as investment allowance.
Investment allowance must be activated by commercial production
from the same field before it can be claimed. The Group has both
unactivated and activated investment allowances which could reduce
future supplementary charge taxation. The Group's policy is that
investment allowance is recognised as a reduction in the charge to
taxation in the years claimed.
7. Income tax (continued)
The major components of income tax (credit)/expense are as
follows:
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
-------------------------------------------------------------- ------------ ------------
Current UK income tax
-------------------------------------------------------------- ------------ ------------
Current income tax charge - 354
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of current income tax of previous
years 140 (745)
-------------------------------------------------------------- ------------ ------------
Current overseas income tax
-------------------------------------------------------------- ------------ ------------
Current income tax charge 2,424 20,894
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of current income tax of previous
years (295) (4,102)
-------------------------------------------------------------- ------------ ------------
Total current income tax 2,269 16,401
-------------------------------------------------------------- ------------ ------------
Deferred UK income tax
-------------------------------------------------------------- ------------ ------------
Relating to origination and reversal of temporary differences 58,184 (277,198)
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of changes in tax rates 1 -
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of deferred income tax of previous
years 2,660 (21,309)
-------------------------------------------------------------- ------------ ------------
Deferred overseas income tax
-------------------------------------------------------------- ------------ ------------
Relating to origination and reversal of temporary differences (5,135) (953)
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of deferred income tax of previous
years 1,848 3,247
-------------------------------------------------------------- ------------ ------------
Total deferred income tax 57,558 (296,213)
-------------------------------------------------------------- ------------ ------------
Income tax (credit)/expense reported in profit or loss 59,827 (279,812)
-------------------------------------------------------------- ------------ ------------
(b) Reconciliation of total income tax charge
A reconciliation between the income tax charge and the product
of accounting profit multiplied by the UK statutory tax rate is as
follows:
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
------------------------------------------------------------------- ------------ ------------
Profit/(loss) before tax (565,975) (729,113)
------------------------------------------------------------------- ------------ ------------
UK statutory tax rate applying to North Sea oil and gas activities
of 40% (2019: 40%) (226,390) (291,645)
------------------------------------------------------------------- ------------ ------------
Supplementary corporation tax non-deductible expenditure 17,761 18,593
------------------------------------------------------------------- ------------ ------------
Petroleum revenue tax (net of income tax benefit) (2,548) -
------------------------------------------------------------------- ------------ ------------
Non-deductible expenditure/income (3,449) 89,746
------------------------------------------------------------------- ------------ ------------
North Sea tax reliefs (106,685) (84,273)
------------------------------------------------------------------- ------------ ------------
Tax in respect of non ring-fence trade 6,737 11,269
------------------------------------------------------------------- ------------ ------------
Deferred tax asset impairment 371,061 -
------------------------------------------------------------------- ------------ ------------
Deferred tax rate changes 1 -
------------------------------------------------------------------- ------------ ------------
Adjustments in respect of prior years 4,352 (22,909)
------------------------------------------------------------------- ------------ ------------
Overseas tax rate differences (1,250) (1,064)
------------------------------------------------------------------- ------------ ------------
Share-based payments 1,097 2,013
------------------------------------------------------------------- ------------ ------------
Other differences (860) (1,542)
------------------------------------------------------------------- ------------ ------------
At the effective income tax rate of (11)% (2019: 38%) 59,827 (279,812)
------------------------------------------------------------------- ------------ ------------
7. Income tax (continued)
(c) Deferred income tax
Deferred income tax relates to the following:
(Credit)/charge
for the year
Group balance recognised in
sheet profit or loss
------------------------------------------- ------------------------ --------------------
2020 2019 2020 2019
$'000 $'000 $'000 $'000
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax liability
------------------------------------------- ----------- ----------- --------- ---------
Accelerated capital allowances 821,253 1,057,805 (236,551) (343,152)
------------------------------------------- ----------- ----------- --------- ---------
821,253 1,057,805
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax asset
------------------------------------------- ----------- ----------- --------- ---------
Losses (825,588) (1,102,534) 276,945 110,455
------------------------------------------- ----------- ----------- --------- ---------
Decommissioning liability (310,697) (284,057) (26,640) (16,103)
------------------------------------------- ----------- ----------- --------- ---------
Other temporary differences (182,529) (226,333) 43,804 (47,413)
------------------------------------------- ----------- ----------- --------- ---------
(1,318,814) (1,612,924)
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax expense 57,558 (296,213)
------------------------------------------- ----------- ----------- --------- ---------
Net deferred tax (assets)/liabilities (497,561) (555,119)
------------------------------------------- ----------- ----------- --------- ---------
Reflected in the balance sheet as follows:
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax assets (503,946) (576,038)
------------------------------------------- ----------- ----------- --------- ---------
Deferred tax liabilities 6,385 20,919
------------------------------------------- ----------- ----------- --------- ---------
Net deferred tax (assets)/liabilities (497,561) (555,119)
------------------------------------------- ----------- ----------- --------- ---------
Reconciliation of net deferred tax assets/(liabilities)
2020 2019
$'000 $'000
------------------------------------------------------------ -------- -------
At 1 January 555,119 258,906
------------------------------------------------------------ -------- -------
Tax income/(expense) during the period recognised in profit
or loss (57,558) 296,213
------------------------------------------------------------ -------- -------
At 31 December 497,561 555,119
------------------------------------------------------------ -------- -------
(d) Tax losses
The Group's deferred tax assets at 31 December 2020 are
recognised to the extent that taxable profits are expected to arise
in the future against which tax losses and allowances in the UK can
be utilised. At 31 December 2020, $371.1 million of the Group's
ring-fence deferred tax assets have not been recognised as there
are currently insufficient future profits forecast to utilise them
fully. In accordance with IAS 12 Income Taxes, the Group assesses
the recoverability of its deferred tax assets at each period end.
Sensitivities have been run on the oil price assumption, with a 10%
change being considered to be a reasonable possible change for the
purposes of sensitivity analysis (see note 2). A 10% reduction in
oil price would result in an additional deferred tax asset
impairment of $328.9 million and a 10% increase in oil price would
result in a reduction in deferred tax asset impairment of $285.4
million.
The Group has unused UK mainstream corporation tax losses of
$320.7 million (2019: $297.8million) for which no deferred tax
asset has been recognised at the balance sheet date due to
uncertainty of the creation of non-ring-fence profits and therefore
uncertainty over the recovery of these losses. In addition, the
Group has not recognised a deferred tax asset for the adjustment to
bond valuations on the adoption of IFRS 9. The benefit of this
deduction is taken over ten years with a deduction of $2.2 million
being taken in the current period with the remaining benefit of
$15.1 million remaining unrecognised.
The Group has unused overseas tax losses in Canada of
approximately CAD$13.5 million (2019: CAD$13.5 million) for which
no deferred tax asset has been recognised at the balance sheet
date. The tax losses in Canada have expiry periods of 20 years,
none of which expire in 2020, and which arose following the change
in control of the Stratic Group in 2010.
The Group has unused Malaysian income tax losses of $14.3
million (2019: $12.2 million) arising in respect of the Tanjong
Baram RSC for which no deferred tax asset has been recognised at
the balance sheet date due to uncertainty of recovery of these
losses.
No deferred tax has been provided on unremitted earnings of
overseas subsidiaries, Finance Act 2009 exempted foreign dividends
from the scope of UK corporation tax where certain conditions are
satisfied.
(e) Changes in legislation
Finance Act 2020 enacted a change in the mainstream corporation
tax rate to 19% with effect from 1 April 2020. As all UK mainstream
corporation tax losses are not recognised there is minimal impact
in 2020 resulting from this change. In the Budget statement on 3
March 2021, it was announced that the corporation tax rate will
increase to 25% from 1 April 2023. This change is expected to have
no impact.
8. Earnings per share
The calculation of earnings per share is based on the profit
after tax and on the weighted average number of Ordinary shares in
issue during the period. Diluted earnings per share is adjusted for
the effects of Ordinary shares granted under the share-based
payment plans, which are held in the Employee Benefit Trust ,
unless it has the effect of increasing the profit or decreasing the
loss attributable to each share.
Basic and diluted earnings per share are calculated as
follows:
Weighted average
Profit/(loss) number of Ordinary Earnings per
after tax shares share
-------------------------------------- -------------------- --------------------- ----------------
Year ended 31 Year ended 31 Year ended 31
December December December
-------------------- --------------------- ----------------
2020 2019 2020 2019 2020 2019
$'000 $'000 million million $ $
-------------------------------------- --------- --------- ---------- --------- ------- -------
Basic (625,802) (449,301) 1,655.0 1,640.1 (0.378) (0.274)
-------------------------------------- --------- --------- ---------- --------- ------- -------
Dilutive potential of Ordinary shares
granted under share-based incentive
schemes - - 15.1 14.7 - -
-------------------------------------- --------- --------- ---------- --------- ------- -------
Diluted(i) (625,802) (449,301) 1,670.1 1,654.8 (0.378) (0.274)
-------------------------------------- --------- --------- ---------- --------- ------- -------
Basic (excluding remeasurements and
exceptional items) (26,187) 214,340 1,655.0 1,640.1 (0.016) 0.131
-------------------------------------- --------- --------- ---------- --------- ------- -------
Diluted (excluding remeasurements
and exceptional items)(i) (26,187) 214,340 1,670.1 1,654.8 (0.016) 0.130
-------------------------------------- --------- --------- ---------- --------- ------- -------
(i) Potential ordinary shares are not treated as dilutive when
they would decrease a loss per share
9. Dividends paid and proposed
The Company paid no dividends during the year ended 31 December
2020 (2019: none). At 31 December 2020, there are no proposed
dividends (2019: none).
10. Property, plant and equipment
Accounting policy
Property, plant and equipment is stated at cost less accumulated
depreciation and accumulated impairment charges.
Cost
Cost comprises the purchase price or cost relating to
development, including the construction, installation and
completion of infrastructure facilities such as platforms,
pipelines and development wells and any other costs directly
attributable to making that asset capable of operating as intended
by management. The purchase price or construction cost is the
aggregate amount paid and the fair value of any other consideration
given to acquire the asset.
The carrying amount of an item of property, plant and equipment
is derecognised on disposal or when no future economic benefits are
expected from its use. The gain or loss arising from the
derecognition of an item of property, plant and equipment is
included in the other operating income or expense line item in the
consolidated income statement when the asset is derecognised.
Development assets
Expenditure relating to development of assets including the
construction, installation and completion of infrastructure
facilities such as platforms, pipelines and development wells, is
capitalised within property, plant and equipment.
Carry arrangements
Where amounts are paid on behalf of a carried party these are
capitalised. Where there is an obligation to make payments on
behalf of a carried party and the timing and amount are uncertain,
a provision is recognised. Where the payment is a fixed monetary
amount, a financial liability is recognised.
Borrowing costs
Borrowing costs directly attributable to the construction of
qualifying assets, which are assets that necessarily take a
substantial period of time to prepare for their intended use, are
capitalised during the development phase of the project until such
time as the assets are substantially ready for their intended
use.
Depletion and depreciation
Oil and gas assets are depleted, on a field-by-field basis,
using the unit of production method based on entitlement to proven
and probable reserves, taking account of estimated future
development expenditure relating to those reserves. Changes in
factors which affect unit of production calculations are dealt with
prospectively. Depletion of oil and gas assets is taken through
cost of sales.
Depreciation on other elements of property, plant and equipment
is provided on a straight-line basis, and taken through general and
administration expenses, at the following rates:
Office furniture and equipment Five years
Fixtures and fittings Ten years
Right-of-use assets* Lease term
* excludes Kraken FPSO which is depleted using the unit of
production method in accordance with the related oil and gas
assets.
Each asset's estimated useful life, residual value and method of
depreciation are reviewed and adjusted if appropriate at each
financial year end. No depreciation is charged on assets under
construction.
10. Property, plant and equipment (continued)
Impairment of tangible and intangible assets (excluding
goodwill)
At each balance sheet date, the Group assesses assets or groups
of assets, called cash generating units (CGUs), for impairment
whenever events or changes in circumstances indicate that the
carrying amount of an asset or CGU may not be recoverable. If any
such indication exists, the Group makes an estimate of the asset's
recoverable amount. An asset's recoverable amount is the higher of
its fair value less costs of disposal and its value in use.
Discounted cash flow models comprising asset-by-asset life of field
projections and risks specific to assets, using Level 3 inputs
(based on IFRS 13 fair value hierarchy), have been used to
determine the recoverable amounts. The cash flows have been
modelled on a post-tax
basis at management's estimate of a market participant WACC. See
note 2 'Key estimates used in calculations'. If the recoverable
amount of an asset is estimated to be less than its carrying
amount, the carrying amount of the asset is reduced to its
recoverable amount. An impairment loss is recognised immediately in
the Group income statement.
Where an impairment loss subsequently reverses, the carrying
amount of the asset is increased to the revised estimate of its
recoverable amount, but only so that the increased carrying amount
does not exceed the carrying amount that would have been determined
had no impairment loss been recognised for the asset in prior
years. A reversal of an impairment loss is recognised immediately
in the Group income statement.
Right-of-use
assets
Office
furniture,
Oil and fixtures (note
gas assets and fittings 24) Total
$'000 $'000 $'000 $'000
---------------------------------------------------- ----------- ------------- ------------ ----------
Cost:
---------------------------------------------------- ----------- ------------- ------------ ----------
At 1 January 2019 8,365,591 60,572 832,502 9,258,665
---------------------------------------------------- ----------- ------------- ------------ ----------
Additions 149,503 3,324 24,587 177,414
---------------------------------------------------- ----------- ------------- ------------ ----------
Change in decommissioning provision 40,097 - - 40,097
---------------------------------------------------- ----------- ------------- ------------ ----------
Change in cost recovery provision (5,895) - - (5,895)
---------------------------------------------------- ----------- ------------- ------------ ----------
Reclass within asset class (2,591) (86) - (2,677)
---------------------------------------------------- ----------- ------------- ------------ ----------
Reclass from/(to) other assets and intangibles
(see note 12) 1,064 (1,357) - (293)
---------------------------------------------------- ----------- ------------- ------------ ----------
At 1 January 2020 8,547,769 62,453 857,089 9,467,311
---------------------------------------------------- ----------- ------------- ------------ ----------
Additions 78,926 1,910 2,812 83,648
---------------------------------------------------- ----------- ------------- ------------ ----------
Change in decommissioning provision (see notes
23) 10,200 - - 10,200
---------------------------------------------------- ----------- ------------- ------------ ----------
Disposals and termination of Tanjong Baram risk
service contract (i) (84,724) (143) (1,412) (86,279)
---------------------------------------------------- ----------- ------------- ------------ ----------
At 31 December 2020 8,552,171 64,220 858,489 9,474,880
---------------------------------------------------- ----------- ------------- ------------ ----------
Accumulated depreciation, depletion and impairment:
---------------------------------------------------- ----------- ------------- ------------ ----------
At 1 January 2019 4,724,614 42,378 81,233 4,848,225
---------------------------------------------------- ----------- ------------- ------------ ----------
Charge for the year 438,242 4,453 90,657 533,352
---------------------------------------------------- ----------- ------------- ------------ ----------
Impairment charge for the year 637,500 - - 637,500
---------------------------------------------------- ----------- ------------- ------------ ----------
Reclass within asset class (2,591) (86) - (2,677)
---------------------------------------------------- ----------- ------------- ------------ ----------
Reclass from/(to) other assets and intangibles
(see note 12) 159 (177) - (18)
---------------------------------------------------- ----------- ------------- ------------ ----------
At 1 January 2020 5,797,924 46,568 171,890 6,016,382
---------------------------------------------------- ----------- ------------- ------------ ----------
Charge for the year 359,258 3,902 82,703 445,863
---------------------------------------------------- ----------- ------------- ------------ ----------
Disposals and termination of Tanjong Baram risk
service contract (i) (42,958) (113) (706) (43,777)
---------------------------------------------------- ----------- ------------- ------------ ----------
Impairment charge for the year 314,335 - 108,160 422,495
---------------------------------------------------- ----------- ------------- ------------ ----------
At 31 December 2020 6,428,559 50,357 362,047 6,840,963
---------------------------------------------------- ----------- ------------- ------------ ----------
Net carrying amount:
---------------------------------------------------- ----------- ------------- ------------ ----------
At 31 December 2020 2,123,612 13,863 496,442 2,633,917
---------------------------------------------------- ----------- ------------- ------------ ----------
At 31 December 2019 2,749,845 15,885 685,199 3,450,929
---------------------------------------------------- ----------- ------------- ------------ ----------
At 1 January 2019 3,640,977 18,194 751,269 4,410,440
---------------------------------------------------- ----------- ------------- ------------ ----------
(i) For details on the termination of the Tanjong Baram risk
service contract see note 5(d)
The net book value at 31 December 2020 includes nil (2019: $70.7
million) of pre-development assets and development assets under
construction. The amount of borrowing costs capitalised during the
year ended 31 December 2020 was nil (2019: $1.4 million relating to
the Dunlin bypass project).
Impairment testing of oil and gas assets
Impairments to the Group's producing oil and gas assets and
reversals of impairments are set out in the table below:
Recoverable
Impairment (charge)/reversal amount(i)
----------------------------------------- ------------------------------ ------------------------
Year ended Year ended
31 December 31 December 31 December 31 December
2020 2019 2020 2019
$'000 $'000 $'000 $'000
----------------------------------------- -------------- -------------- ----------- -----------
North Sea (422,495) (637,500) 1,086,348 46,462
----------------------------------------- -------------- -------------- ----------- -----------
Malaysia - - - -
----------------------------------------- -------------- -------------- ----------- -----------
Net pre-tax impairment reversal/(charge) (422,495) (637,500)
----------------------------------------- -------------- -------------- ----------- -----------
(i) Recoverable amount has been determined on a fair value less
costs of disposal basis (see note 2 for further details of
significant estimates and judgements made in relation to
impairments). The amounts disclosed above are in respect of assets
where an impairment (or reversal) has been recorded. Assets which
did not have any impairment or reversal are excluded from the
amounts disclosed
Impairment charges of $314.3 million (2019: $637.5 million) and
$108.2 (2019: nil) were recognised in respect of oil and gas assets
and right-of-use assets respectively within the North Sea
reportable segment. The impairments are attributable primarily to
producing assets and principally arose as a result of changes to
the Group's oil price assumptions during the year.
10. Property, plant and equipment (continued)
The Group's recoverable value of assets is highly sensitive,
inter alia, to oil price achieved and production volumes. As stated
in note 2, there is uncertainty due to climate change and
international governmental intervention to reduce emissions and the
likely impact this will have on gas and oil demand in respect of
future prices. A sensitivity has been run on the oil price
assumption, with a 10.0% change being considered to be a reasonable
possible change for the purposes of sensitivity analysis (see note
2). A 10.0% reduction in oil price would increase the net pre-tax
impairment by approximately $266.0 million, with the additional
impairment attributable to the fields in the North Sea.
A sensitivity has also been run on the discount rate assumption,
with a 1.0% change being considered to be a reasonable possible
change for the purposes of sensitivity analysis (see note 2). A
1.0% increase in discount rate would increase the net impairment by
approximately $53.6 million, with the additional impairment
attributable to the fields in the North Sea.
The oil price sensitivity analysis above does not, however,
represent management's best estimate of any impairments that might
be recognised as they do not fully incorporate consequential
changes that may arise, such as reductions in costs and changes to
business plans, phasing of development, levels of reserves and
resources, and production volumes. As the extent of a price
reduction increases, the more likely it is that costs would
decrease across the industry. The oil price sensitivity analysis
therefore does not reflect a linear relationship between price and
value that can be extrapolated.
11. Goodwill
Accounting policy
Cost
Goodwill arising on a business combination is initially measured
at cost, being the excess of the cost of the business combination
over the net fair value of the identifiable assets, liabilities and
contingent liabilities of the entity at the date of acquisition. If
the fair value of the net assets acquired is in excess of the
aggregate consideration transferred, the Group reassesses whether
it has correctly identified all of the assets acquired and all of
the liabilities assumed and reviews the procedures used to measure
the amounts to be recognised at the acquisition date. If the
reassessment still results in an excess of the fair value of net
assets acquired over the aggregate consideration transferred, the
gain is recognised in profit or loss.
Impairment of goodwill
Following initial recognition, goodwill is stated at cost less
any accumulated impairment losses. In accordance with IAS 36
Impairment of Assets, goodwill is reviewed for impairment annually
or more frequently if events or changes in circumstances indicate
the recoverable amount of the CGU to which the goodwill relates
should be assessed.
For the purposes of impairment testing, goodwill acquired is
allocated to the CGU that is expected to benefit from the synergies
of the combination. Each unit or units to which goodwill is
allocated represents the lowest level within the Group at which the
goodwill is monitored for internal management purposes. Impairment
is determined by assessing the recoverable amount of the CGU to
which the goodwill relates. Where the recoverable amount of the CGU
is less than the carrying amount of the CGU containing goodwill, an
impairment loss is recognised. Impairment losses relating to
goodwill cannot be reversed in future periods.
A summary of goodwill is presented below:
2020 2019
$'000 $'000
----------------------------- -------- ---------
Cost and net carrying amount
----------------------------- -------- ---------
At 1 January 134,400 283,950
----------------------------- -------- ---------
Impairment - (149,550)
----------------------------- -------- ---------
At 31 December 134,400 134,400
----------------------------- -------- ---------
The majority of the goodwill, $94.6 million, relates to the 75%
acquisition of the Magnus oil field and associated interests. The
remaining goodwill balance arose from the acquisition of Stratic
and PEDL in 2010 and the Greater Kittiwake Area asset in 2014.
Impairment testing of goodwill
Goodwill, which has been acquired through business combinations,
has been allocated to the UK North Sea segment CGU, and this is
therefore the lowest level at which goodwill is reviewed. The UK
North Sea is a combination of oil and gas assets, as detailed
within property, plant and equipment (note 10).
The recoverable amounts of the CGU and fields have been
determined on a fair value less costs of disposal basis. Discounted
cash flow models comprising asset-by-asset life of field
projections and risks specific to assets, using Level 3 inputs
(based on IFRS 13 fair value hierarchy), have been used to
determine the recoverable amounts. See 'Key estimates used in
calculations' (note 2). The cash flows have been modelled on a
post-tax basis at management's estimate of a market participant
WACC. An impairment charge of nil was taken in 2020 (2019: $149.6
million) based on a fair value less costs to dispose valuation of
the North Sea CGU, as described above.
Sensitivity to changes in assumptions
The Group's recoverable value of assets is highly sensitive,
inter alia, to oil price achieved and production volumes. A
sensitivity has been run on the oil price assumption, with a 10.0%
change being considered to be a reasonable possible change for the
purposes of sensitivity analysis (see note 2). A 10.0% reduction in
oil price would result in a net impairment of $14 million (2019:
full impairment of goodwill). A 12.6% reduction in oil price would
fully impair goodwill (2019: 5.0%).
12. Intangible oil and gas assets
Accounting policy
Exploration and appraisal assets
Exploration and appraisal have indefinite useful lives and are
accounted for using the successful efforts method of accounting.
Pre-licence costs are expensed in the period in which they are
incurred. Expenditure directly associated with exploration,
evaluation or appraisal activities is initially capitalised as an
intangible asset. Such costs include the costs of acquiring an
interest, appraisal well drilling costs, payments to contractors
and an appropriate share of directly attributable overheads
incurred during the evaluation phase. For such appraisal activity,
which may require drilling of further wells, costs continue to be
carried as an asset whilst related hydrocarbons are considered
capable of commercial development. Such costs are subject to
technical, commercial and management review to confirm the
continued intent to develop, or otherwise extract value. When this
is no longer the case, the costs are written off as exploration and
evaluation expenses in the Group income statement. When exploration
licences are relinquished without further development, any previous
impairment loss is reversed and the carrying costs are written off
through the Group income statement. When assets are declared part
of a commercial development, related costs are transferred to
property, plant and equipment. All intangible oil and gas assets
are assessed for any impairment prior to transfer and any
impairment loss is recognised in the Group income statement.
During the year ended 31 December 2020, there was no impairment
of historical exploration and appraisal expenditures (2019: $25.4
million).
Accumulated Net carrying
Cost impairment amount
$'000 $'000 $'000
------------------------------------------------------- -------- ----------- ------------
At 31 December 2018 165,586 (113,783) 51,803
------------------------------------------------------- -------- ----------- ------------
Additions 3,241 - 3,241
------------------------------------------------------- -------- ----------- ------------
Write-off of relinquished licences previously impaired (583) 583 -
------------------------------------------------------- -------- ----------- ------------
Unsuccessful exploration expenditure written off - (150) (150)
------------------------------------------------------- -------- ----------- ------------
Change in decommissioning provision (see note 23) (2,218) - (2,218)
------------------------------------------------------- -------- ----------- ------------
Impairment charge for the year - (25,398) (25,398)
------------------------------------------------------- -------- ----------- ------------
Reclass within asset class 8,645 (8,645) -
------------------------------------------------------- -------- ----------- ------------
Reclass from/(to) tangible fixed assets (see note 10) 293 (18) 275
------------------------------------------------------- -------- ----------- ------------
At 31 December 2019 174,964 (147,411) 27,553
------------------------------------------------------- -------- ----------- ------------
Write-off of relinquished licences previously impaired (12,645) 12,645 -
------------------------------------------------------- -------- ----------- ------------
Other (7) - (7)
------------------------------------------------------- -------- ----------- ------------
At 31 December 2020 162,312 (134,766) 27,546
------------------------------------------------------- -------- ----------- ------------
13. Inventories
Accounting policy
Inventories of consumable well supplies and inventories of
hydrocarbons are stated at the lower of cost and NRV, cost being
determined on an average cost basis.
2020 2019
$'000 $'000
------------------------ ------- -------
Hydrocarbon inventories 20,509 17,216
------------------------ ------- -------
Well supplies 39,275 61,428
------------------------ ------- -------
59,784 78,644
------------------------ ------- -------
During 2020, inventories of $21.6 million (2019: $20.6 million)
were recognised within cost of sales in the Group income
statement.
The inventory valuation at 31 December 2020 is stated net of a
provision of $56.7 million (2019: $31.8 million) to write down well
supplies to their estimated net realisable value. The net charge to
the income statement in the year in respect of well supplies
provisions, primarily associated with decommissioned assets, was
$24.9 million (2019: $14.6 million).
14. Cash and cash equivalents
2020 2019
$'000 $'000
------------------------------------------------------------- -------- -------
Available cash
------------------------------------------------------------- -------- -------
Cash at bank 113,185 137,365
------------------------------------------------------------- -------- -------
Short-term deposits - 6,849
------------------------------------------------------------- -------- -------
Total available cash 113,185 144,214
------------------------------------------------------------- -------- -------
Ring-fenced cash
------------------------------------------------------------- -------- -------
Joint venture accounts 74,447 32,365
------------------------------------------------------------- -------- -------
Operational accounts 33,523 41,620
------------------------------------------------------------- -------- -------
Total ring-fenced cash 107,970 73,985
------------------------------------------------------------- -------- -------
Total cash at bank and in hand 221,155 218,199
------------------------------------------------------------- -------- -------
Restricted cash - Cash subject to currency controls or other
legal restrictions
------------------------------------------------------------- -------- -------
Cash held in escrow 1,675 1,611
------------------------------------------------------------- -------- -------
Cash collateral - 646
------------------------------------------------------------- -------- -------
Total restricted cash - Cash subject to currency controls
or other legal restrictions 1,675 2,257
------------------------------------------------------------- -------- -------
Total cash and cash equivalents 222,830 220,456
------------------------------------------------------------- -------- -------
14. Cash and cash equivalents (continued)
The carrying value of the Group's cash and cash equivalents is
considered to be a reasonable approximation to their fair value due
to their short-term maturities. Ring-fenced cash includes joint
venture accounts and cash held in operational accounts, as detailed
below.
Short-term deposits
At 31 December 2020, nil (2019: $6.8 million) was placed on
short-term deposit in order to cash collateralise the Group's
letter of credit.
Joint venture accounts
Joint venture accounts include the cash called for the
operations of the relevant asset, from both EnQuest and partners,
based on equity share.
Operational accounts
Operational accounts include cash balances that are available
for the operating, investing and financing activities of the
following specific assets. This cash includes:
-- $17.4 million Sculptor Capital working capital for use only
for the activities of the ring-fenced 15% interest in the Kraken
oil field (see note 18);
-- Nil Magnus asset working capital for use only for activities
of Magnus and maintained for the repayment mechanism with BP for
the contingent consideration (see note 22); and
-- $16.2 million SVT working capital for use only with the activities of SVT (see note 18).
Restricted cash
Included within the cash balance at 31 December 2020 is
restricted cash of $1.7 million (2019: $2.3 million). The
restricted cash balance is stated net of a provision of $2.5
million (2019: $2.5 million) which relates to cash held in escrow
in respect of the unwound acquisition of the Tunisian assets of PA
Resources.
15. Financial instruments and fair value measurement
Accounting policy
A financial instrument is any contract that gives rise to a
financial asset of one entity and a financial liability or equity
instrument of another entity. Financial instruments are recognised
when the Group becomes a party to the contractual provisions of the
financial instrument.
Financial assets and financial liabilities are offset and the
net amount is reported in the Group balance sheet if there is a
currently enforceable legal right to offset the recognised amounts
and there is an intention to settle on a net basis.
Financial assets
Financial assets are classified, at initial recognition, as
amortised cost, fair value through other comprehensive income
('FVOCI'), or fair value through profit or loss ('FVPL'). The
classification of financial assets at initial recognition depends
on the financial assets' contractual cash flow characteristics and
the Group's business model for managing them. The Group does not
currently hold any financial assets at FVOCI, i.e. debt financial
assets.
Financial assets are derecognised when the contractual rights to
the cash flows from the financial asset expire, or when the
financial asset and substantially all the risks and rewards are
transferred.
Financial assets at amortised cost
Trade receivables, other receivables and joint operation
receivables are measured initially at fair value and subsequently
recorded at amortised cost, using the effective interest rate
('EIR') method, and are subject to impairment. Gains and losses are
recognised in profit or loss when the asset is derecognised,
modified or impaired and EIR amortisation is included within
finance costs.
The Group measures financial assets at amortised cost if both of
the following conditions are met:
-- The financial asset is held within a business model with the
objective to hold financial assets in order to collect contractual
cash flows; and
-- The contractual terms of the financial asset give rise on
specified dates to cash flows that are solely payments of principal
and interest on the principal amount outstanding.
.
Prepayments, which are not financial assets, are measured at
historical cost.
Impairment of financial assets
The Group recognises a provision for expected credit loss
('ECL'), where material, for all financial assets held at the
balance sheet date. ECLs are based on the difference between the
contractual cash flows due to the Group, and the discounted actual
cash flows that are expected to be received. Where there has been
no significant increase in credit risk since initial recognition,
the loss allowance is equal to 12-month expected credit losses.
Where the increase in credit risk is considered significant,
lifetime credit losses are provided. For trade receivables a
lifetime credit loss is recognised on initial recognition where
material.
The provision rates are based on days past due for groupings of
customer segments with similar loss patterns (i.e. by geographical
region, product type, customer type and rating) and is based on its
historical credit loss experience, adjusted for forward-looking
factors specific to the debtors and the economic environment. The
Group evaluates the concentration of risk with respect to trade
receivables and contract assets as low, as its customers are joint
venture partners and there are no indications of change in risk.
Generally, trade receivables are written off if past due for more
than one year and are not subject to enforcement activity.
Financial liabilities
Financial liabilities are classified, at initial recognition, as
amortised cost or at fair value through profit or loss.
Financial liabilities are derecognised when they are
extinguished, discharged, cancelled or they expire. When an
existing financial liability is replaced by another from the same
lender on substantially different terms, or the terms of an
existing liability are substantially modified, such an exchange or
modification is treated as the derecognition of the original
liability and the recognition of a new liability. The difference in
the respective carrying amounts is recognised in the Group income
statement.
Financial liabilities at amortised cost
Loans and borrowings, trade payables and other creditors are
measured initially at fair value net of directly attributable
transaction costs and subsequently recorded at amortised cost,
using the EIR method. Loans and borrowings are interest bearing.
Gains and losses are recognised in profit or loss when the
liability is derecognised and EIR amortisation is included within
finance costs.
15. Financial instruments and fair value measurement
(continued)
Financial instruments at fair value through profit or loss
The Group holds derivative financial instruments classified as
held for trading, not designated as effective hedging instruments.
The derivative financial instruments include forward currency
contracts and commodity contracts, to address the respective risks,
see note 27. Derivatives are carried as financial assets when the
fair value is positive and as financial liabilities when the fair
value is negative.
Financial instruments at FVPL are carried in the Group balance
sheet at fair value with net changes in fair value recognised in
the Group income statement. Unrealised mark-to-market changes in
the remeasurement of open derivative contracts at each period end
is recognised within remeasurements, with the recycling of realised
amounts from remeasurements into Business performance income when a
derivative instrument matures. Option premium received or paid for
commodity derivatives are recognised in remeasurements.
Financial assets with cash flows that are not solely payments of
principal and interest are classified and measured at fair value
through profit or loss, irrespective of the business model. All
financial assets not classified as measured at amortised cost or
FVOCI as described above are measured at FVPL. Financial
instruments with embedded derivatives are considered in their
entirety when determining whether their cash flows are solely
payment of principal and interest.
The Group also holds contingent consideration (see note 22) and
a listed equity investment (see note 19). The movements of both are
recognised within remeasurements in the Group income statement.
Fair value measurement
The following table provides the fair value measurement
hierarchy of the Group's assets and liabilities:
Quoted
prices Significant Significant
in active observable unobservable
markets inputs inputs
(Level (Level (Level
Total 1) 2) 3)
31 December 2020 $'000 $'000 $'000 $'000
-------------------------------------------- -------- ---------- ----------- -------------
Financial assets measured at fair value:
-------------------------------------------- -------- ---------- ----------- -------------
Other financial assets at FVPL
-------------------------------------------- -------- ---------- ----------- -------------
Quoted equity shares 7 7 - -
-------------------------------------------- -------- ---------- ----------- -------------
Liabilities measured at fair value:
-------------------------------------------- -------- ---------- ----------- -------------
Derivative financial liabilities at FVPL
-------------------------------------------- -------- ---------- ----------- -------------
Oil commodity derivative contracts 19 2,007 - 2,007 -
-------------------------------------------- -------- ---------- ----------- -------------
Other financial liabilities measured at
FVPL
-------------------------------------------- -------- ---------- ----------- -------------
Contingent consideration 22 522,261 - - 522,261
-------------------------------------------- -------- ---------- ----------- -------------
Liabilities measured at amortised cost
for which fair values are disclosed below:
-------------------------------------------- -------- ---------- ----------- -------------
Interest-bearing loans and borrowings 18 454,209 - - 454,209
-------------------------------------------- -------- ---------- ----------- -------------
Obligations under leases 24 647,846 - - 647,846
-------------------------------------------- -------- ---------- ----------- -------------
Retail bond 18 225,943 225,943 - -
-------------------------------------------- -------- ---------- ----------- -------------
High yield bond 18 537,602 537,602 - -
-------------------------------------------- -------- ---------- ----------- -------------
Quoted
prices Significant Significant
in active observable unobservable
markets inputs inputs
(Level (Level (Level
Total 1) 2) 3)
31 December 2019 $'000 $'000 $'000 $'000
-------------------------------------------- -------- ---------- ----------- -------------
Financial assets measured at fair value:
-------------------------------------------- -------- ---------- ----------- -------------
Derivative financial assets at FVPL
-------------------------------------------- -------- ---------- ----------- -------------
Oil commodity derivative contracts 19 288 - 288 -
-------------------------------------------- -------- ---------- ----------- -------------
Foreign currency derivative contracts 19 1,932 - 1,932 -
-------------------------------------------- -------- ---------- ----------- -------------
Other financial assets at FVPL
-------------------------------------------- -------- ---------- ----------- -------------
Quoted equity shares 11 11 - -
-------------------------------------------- -------- ---------- ----------- -------------
Liabilities measured at fair value:
-------------------------------------------- -------- ---------- ----------- -------------
Derivative financial liabilities at FVPL
-------------------------------------------- -------- ---------- ----------- -------------
Oil commodity derivative contracts 19 11,073 - 11,073 -
-------------------------------------------- -------- ---------- ----------- -------------
Other financial liabilities measured at
FVPL
-------------------------------------------- -------- ---------- ----------- -------------
Contingent consideration 22 657,261 - - 657,261
-------------------------------------------- -------- ---------- ----------- -------------
Liabilities measured at amortised cost
for which fair values are disclosed below:
-------------------------------------------- -------- ---------- ----------- -------------
Interest-bearing loans and borrowings 18 661,638 - - 661,638
-------------------------------------------- -------- ---------- ----------- -------------
Obligations under leases 24 716,166 - - 716,166
-------------------------------------------- -------- ---------- ----------- -------------
Retail bond 18 195,948 195,948 - -
-------------------------------------------- -------- ---------- ----------- -------------
High yield bond 18 655,462 655,462 - -
-------------------------------------------- -------- ---------- ----------- -------------
Fair value hierarchy
All financial instruments for which fair value is recognised or
disclosed are categorised within the fair value hierarchy, based on
the lowest level input that is significant to the fair value
measurement as a whole, as follows:
Level 1: Quoted (unadjusted) market prices in active markets for
identical assets or liabilities; Level 2: Valuation techniques for
which the lowest level input that is significant to the fair value
measurement is directly (i.e. as prices) or indirectly (i.e.
derived from prices) observable; Level 3: Valuation techniques for
which the lowest level input that is significant to the fair value
measurement is unobservable.
Derivative financial instruments are valued by counterparties,
with the valuations reviewed internally and corroborated with
readily available market data (Level 2). Contingent consideration
is measured at FVPL using the Level 3 valuation processes disclosed
in note 22. There have been no transfers between Level 1 and Level
2 during the period (2019: no transfers).
For the financial liabilities measured at amortised costs but
for which fair value disclosures are required, the fair value of
the bonds classified as Level 1 was derived from quoted prices for
that financial instrument. Both interest-bearing loans and
borrowings and obligations under finance leases were calculated
using the discounted cash flow method to capture the present value
(Level 3).
16. Trade and other receivables
2020 2019
$'000 $'000
------------------------------- ------- --------
Current
------------------------------- ------- --------
Trade receivables 24,604 117,149
------------------------------- ------- --------
Joint venture receivables 53,121 119,519
------------------------------- ------- --------
Under-lift position 15,690 17,651
------------------------------- ------- --------
VAT receivable 10,307 6,887
------------------------------- ------- --------
Other receivables 1,441 3,374
------------------------------- ------- --------
105,163 264,580
------------------------------- ------- --------
Prepayments and accrued income 13,552 14,922
------------------------------- ------- --------
118,715 279,502
------------------------------- ------- --------
The carrying value of the Group's trade, joint venture and other
receivables as stated above are considered to be a reasonable
approximation to their fair value largely due to their short-term
maturities. Under-lift is valued at the lower of cost or NRV at the
prevailing balance sheet date (note 5(b)).
Trade receivables are non-interest-bearing and are generally on
15 to 30 day terms. Joint venture receivables relate to amounts
billable to, or recoverable from, joint venture partners.
Receivables are reported net of any ECL with no losses recognised
as at 31 December 2020 or 2019. The Group's ECL estimates were not
significantly impacted by Brexit or COVID-19 during 2020.
17. Trade and other payables
2020 2019
$'000 $'000
------------------------ ------- -------
Current
------------------------ ------- -------
Trade payables 41,090 92,238
------------------------ ------- -------
Accrued expenses 179,590 258,539
------------------------ ------- -------
Over-lift position 12,732 46,201
------------------------ ------- -------
Joint venture creditors 16,647 1,788
------------------------ ------- -------
Other payables 5,096 21,089
------------------------ ------- -------
255,155 419,855
------------------------ ------- -------
Classified as:
------------------------ ------- -------
Current 255,155 419,855
------------------------ ------- -------
Non-current - -
------------------------ ------- -------
255,155 419,855
------------------------ ------- -------
The carrying value of the Group's trade and other payables as
stated above is considered to be a reasonable approximation to
their fair value largely due to the short-term maturities. Certain
trade and other payables will be settled in currencies other than
the reporting currency of the Group, mainly in Sterling. Trade
payables are normally non-interest-bearing and settled on terms of
between 10 and 30 days.
Accrued expenses include accruals for capital and operating
expenditure in relation to the oil and gas assets and interest
accruals.
18. Loans and borrowings
2020 2019
$'000 $'000
----------- --------- ---------
Borrowings 452,284 659,013
----------- --------- ---------
Bonds 1,045,041 966,231
----------- --------- ---------
1,497,325 1,625,244
----------- --------- ---------
(a) Borrowings
The Group's borrowings are carried at amortised cost as
follows:
2020 2019
----------------------------------------- ---------------------------- ----------------------------
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
----------------------------------------- --------- ------- -------- --------- ------- --------
Credit facility 377,270 - 377,270 475,097 - 475,097
----------------------------------------- --------- ------- -------- --------- ------- --------
Sculptor Capital facility 67,701 (1,925) 65,776 122,912 (2,625) 120,287
----------------------------------------- --------- ------- -------- --------- ------- --------
SVT working capital facility 9,238 - 9,238 31,899 - 31,899
----------------------------------------- --------- ------- -------- --------- ------- --------
Tanjong Baram project financing facility - - - 31,730 - 31,730
----------------------------------------- --------- ------- -------- --------- ------- --------
Total borrowings 454,209 (1,925) 452,284 661,638 (2,625) 659,013
----------------------------------------- --------- ------- -------- --------- ------- --------
Due within one year 414,430 165,589
----------------------------------------- --------- ------- -------- --------- ------- --------
Due after more than one year 37,854 493,424
----------------------------------------- --------- ------- -------- --------- ------- --------
Total borrowings 452,284 659,013
----------------------------------------- --------- ------- -------- --------- ------- --------
See liquidity risk - note 27 for the timing of cash outflows
relating to loans and borrowings
18. Loans and borrowings (continued)
Credit facility
On 21 November 2016, the Group completed a loan restructuring
and entered into an amended and restated credit agreement, which
included the following terms:
-- Commitments split into a term facility of $1.125 billion and
a revolving facility of $75 million (together the 'credit
facility');
-- Maturity date of October 2021;
-- Amortisation payable from 1 April 2018, the first scheduled amortisation date;
-- Borrowings subject to mandatory repayment out of excess cash
flow (excluding amounts required for approved capital expenditure),
assessed on a six-monthly basis;
-- Borrowings up to $890.7 million subject to interest at USD
LIBOR plus a margin of 4.75%, paid in cash;
-- Borrowings in excess of $890.7 million subject to interest at
USD LIBOR plus a margin of 5.25%, paid in cash, with a further
3.75% interest accrued and added to the Payment In Kind ('PIK')
amount at maturity of each loan's maturity period;
-- PIK amount repayable at maturity and subject to 9.0%
interest, which is capitalised and added to the PIK amount on each
30 June and 31 December.
At 31 December 2020, the carrying amount of the credit facility
on the balance sheet was $377.8 million, comprising the loan
principal drawn down of $360.0 million, $17.3 million of interest
capitalised to the PIK amount and $0.5 million accrued interest
(note 17) (2019: carrying amount $477.4 million, principal drawn
down $460.0 million, PIK $15.8 million and accrued interest $1.6
million).
At 31 December 2020, after allowing for letter of credit
utilisation of $28.8 million, $46.2 million remained available for
drawdown under the credit facility (2019: $6.8 million and $68.2
million, respectively).
Sculptor Capital facility
On 24 September 2018, the Group entered into a $175.0 million
financing facility with Sculptor Capital Management Inc. The
facility was drawn down in full and is repayable in five years from
initial availability of the facility. Interest accrues at 6.3%
annual effective rate plus one-month USD LIBOR. The financing is
ring-fenced on a 15% interest in the Kraken oil field and will be
repaid out of the cash flows associated with the interest over a
maximum of five years.
SVT working capital facility
On 1 December 2020, EnQuest NNS Limited extended, for a further
three years, the GBP42.0 million revolving loan facility with a
joint operator partner to fund the short-term working capital cash
requirements on the acquisition of SVT and associated interests.
The facility is able to be drawn down against, in instalments, and
accrues interest at 1.0% per annum plus GBP LIBOR.
Tanjong Baram project financing facility
On 25 October 2017, the Group entered into a $34.6 million
financing facility in Malaysia with Castleton Commodities Merchant
Asia Co. Pte Ltd. In June 2020, EnQuest made an early voluntary
repayment of the entire $31.7 million of the Tanjong Baram project
finance facility.
Trade Creditor Facility
In April 2020, the Group entered into a $15.0 million facility
with a supplier, in relation to the provision of a drilling
contract. Any amounts drawn down under the facility, along with
associated accrued interest at 4%, would be repayable in two
instalments in 2021. No amounts were drawn as at 31 December
2020.
(b) Bonds
The Group's bonds are carried at amortised cost as follows:
2020 2019
------------------------------------ ------------------------------- ----------------------------
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
------------------------------------ ---------- ------- ---------- --------- ------- --------
High yield bond 799,194 (2,666) 796,528 746,056 (4,483) 741,573
------------------------------------ ---------- ------- ---------- --------- ------- --------
Retail bond 249,161 (648) 248,513 225,747 (1,089) 224,658
------------------------------------ ---------- ------- ---------- --------- ------- --------
Total bonds due after more than one
year 1,048,355 (3,314) 1,045,041 971,803 (5,572) 966,231
------------------------------------ ---------- ------- ---------- --------- ------- --------
High yield bond
In April 2014, the Group issued a $650.0 million high yield
bond. On 21 November 2016, the high yield bond was amended pursuant
to a scheme of arrangement whereby all existing notes were
exchanged for new notes. The new high yield notes continue to
accrue a fixed coupon of 7.0% payable semi-annually in arrears. The
interest is only payable in cash if the 'Cash Payment Condition' is
satisfied, being the average of the Daily Brent Oil Prices during
the period of six calendar months immediately preceding the 'Cash
Payment Condition Determination Date' is equal to or above $65/bbl.
The 'Cash Payment Condition Determination Date' is the date falling
one calendar month prior to the relevant interest payment date. If
the 'Cash Payment Condition' is not satisfied, interest will not be
paid in cash but instead will be capitalised and satisfied through
the issue of additional high yield notes ('Additional HY Notes').
$27.5 million of accrued, unpaid interest as at the restructuring
date was capitalised and added to the principal amount of the new
high yield notes issued pursuant to the scheme.
During the year the maturity date of the new high yield notes
was automatically extended to 15 October 2023 as the credit
facility had not been repaid or refinanced in full prior to 15
October 2020.
The total carrying value of the bond as at 31 December 2020 is
$796.5 million (2019: $741.6 million). This includes bond principal
of $799.2 million (2019: $746.1 million) less unamortised fees of
$2.7 million (2019: $4.5 million). The high yield bond does not
include accrued interest of $11.8 million (2019: $11 million) and
liability for the IFRS 9 Financial Instruments loss on modification
of $4.6 million (2019: $2.2 million), which are reported within
trade and other payables. The fair value of the high yield bond is
disclosed in note 15.
18. Loans and borrowings (continued)
Retail bond
In 2013, the Group issued a GBP155.0 million retail bond. On 21
November 2016, the retail bond was amended pursuant to a scheme of
arrangement whereby all existing notes were exchanged for new
notes. The new retail notes continue to accrue a fixed coupon of
7.0% payable semi-annually in arrears. The interest is only payable
in cash if the 'Cash Payment Condition' is satisfied, being the
average of the Daily Brent Oil Prices during the period of six
calendar months immediately preceding the 'Cash Payment Condition
Determination Date' is equal to or above $65/bbl. The 'Cash Payment
Condition Determination Date' is the date falling one calendar
month prior to the relevant interest payment date. If the 'Cash
Payment Condition' is not satisfied, interest will not be paid in
cash but instead will be capitalised and satisfied through the
issue of additional retail notes ('Additional Retail Notes').
During the year the maturity date of the new high yield notes
was automatically extended to 15 October 2023 as the credit
facility had not been repaid or refinanced in full prior to 15
October 2020.
The total carrying value of the bond as at 31 December 2020 is
$248.5 million (2019: $224.7 million). This includes bond principal
of $249.2 million (2019: $225.7 million) less unamortised fees of
$0.6 million (2019: $1.1 million). The retail yield bond does not
include accrued interest of $6.3 million (2019: $6.0 million) and
liability for the IFRS 9 Financial Instruments loss on modification
of $11.9 million (2019: $10.5 million), which are reported within
trade and other payables. The fair value of the retail bond is
disclosed in note 15.
19. Other financial assets and financial liabilities
(a) Summary as at year end
2020 2019
-------------------------------------- ------------------- -------------------
Assets Liabilities Assets Liabilities
$'000 $'000 $'000 $'000
-------------------------------------- ------ ----------- ------ -----------
Fair value through profit or loss:
-------------------------------------- ------ ----------- ------ -----------
Derivative commodity contracts - 2,007 288 11,073
-------------------------------------- ------ ----------- ------ -----------
Derivative foreign exchange contracts - - 1,932 -
-------------------------------------- ------ ----------- ------ -----------
Amortised cost:
-------------------------------------- ------ ----------- ------ -----------
Other receivables - - 6,863 -
-------------------------------------- ------ ----------- ------ -----------
Total current - 2,007 9,083 11,073
-------------------------------------- ------ ----------- ------ -----------
Fair value through profit or loss:
-------------------------------------- ------ ----------- ------ -----------
Quoted equity shares 7 - 11 -
-------------------------------------- ------ ----------- ------ -----------
Total non-current 7 - 11 -
-------------------------------------- ------ ----------- ------ -----------
(b) Income statement impact
The income/(expense) recognised for derivatives are as
follows:
Revenue and
other operating
income Cost of sales
---------------------------- -------------------- --------------------
Realised Unrealised Realised Unrealised
Year ended 31 December 2020 $'000 $'000 $'000 $'000
---------------------------- -------- ---------- -------- ----------
Commodity options 24,659 (136) - -
---------------------------- -------- ---------- -------- ----------
Commodity swaps (36,912) 8,941 - -
---------------------------- -------- ---------- -------- ----------
Commodity futures 6,194 (27) - -
---------------------------- -------- ---------- -------- ----------
Foreign exchange contracts - - 572 (1,932)
---------------------------- -------- ---------- -------- ----------
(6,059) 8,778 572 (1,932)
---------------------------- -------- ---------- -------- ----------
Revenue and
other operating
income Cost of sales
------------------------------------------- -------------------- --------------------
Realised Unrealised Realised Unrealised
Year ended 31 December 2019 $'000 $'000 $'000 $'000
------------------------------------------- -------- ---------- -------- ----------
Commodity options 10,517 (55,513) - -
------------------------------------------- -------- ---------- -------- ----------
Commodity swaps 19,813 (10,021) - -
------------------------------------------- -------- ---------- -------- ----------
Commodity futures (4,467) 159 - -
------------------------------------------- -------- ---------- -------- ----------
Commodity collar on prepayment transaction (1,107) - - -
------------------------------------------- -------- ---------- -------- ----------
Foreign exchange contracts - - (2,713) 1,684
------------------------------------------- -------- ---------- -------- ----------
Carbon forwards - - 1,006 (2,062)
------------------------------------------- -------- ---------- -------- ----------
24,756 (65,375) (1,707) (378)
------------------------------------------- -------- ---------- -------- ----------
(c) Commodity contracts
The Group uses derivative financial instruments to manage its
exposure to the oil price, including put and call options, swap
contracts and futures.
For the year ended 31 December 2020, gains totalling $2.7
million (2019: losses of $40.6 million) were recognised in respect
of commodity contracts designated as FVPL. This included losses
totalling $6.1 million (2019: gains of $24.8 million) realised on
contracts that matured during the year, and mark-to-market
unrealised gains totalling $8.8 million (2019: losses of $65.4
million). Of the realised amounts recognised during the year, a
gain of $6.2 million (2019: gain of $4.9 million) was realised in
Business performance revenue in respect of the premium income
received on sale of these options.
The mark-to-market value of the Group's open contracts as at 31
December 2020 was a liability of $2.0 million (2019: liability of
$10.8 million).
19. Other financial assets and financial liabilities
(continued)
(d) Foreign currency contracts
The Group enters into a variety of foreign currency contracts,
primarily in relation to Sterling. During the year ended 31
December 2020, losses totalling $1.4 million (2019: losses of $1.0
million) were recognised in the income statement. This included
realised gains totalling $0.6 million (2019: loss of $2.7 million)
on contracts that matured in the year.
The mark-to-market value of the Group's open contracts as at 31
December 2020 was nil (2019: asset of $1.9 million).
(e) Other receivables
2020 2019
$'000 $'000
------------------------- ------- -------
At 1 January 6,874 15,506
------------------------- ------- -------
Change in fair value (4) (20)
------------------------- ------- -------
Utilised during the year (7,138) (9,517)
------------------------- ------- -------
Unwinding of discount 275 905
------------------------- ------- -------
At 31 December 7 6,874
------------------------- ------- -------
Current - 6,863
------------------------- ------- -------
Non-current 7 11
------------------------- ------- -------
7 6,874
------------------------- ------- -------
Other receivables
2020 2019
Comprised of: $'000 $'000
---------------- ------ ------
BUMI receivable - 6,863
---------------- ------ ------
Other 7 11
---------------- ------ ------
Total 7 6,874
---------------- ------ ------
In August 2016, EnQuest agreed with Armada Kraken PTE Ltd
('BUMI') that BUMI would refund $65 million (EnQuest's share being
$45.8 million) of a $100.0 million lease prepayment made in 2014
for the FPSO for the Kraken field. This refund is receivable from
2018 onwards. A total of $7.1 million was collected during the
period, with the refund now fully settled.
20. Share capital and premium
Accounting policy
Share capital and share premium
The balance classified as equity share capital includes the
total net proceeds (both nominal value and share premium) on issue
of registered share capital of the parent company. Share issue
costs associated with the issuance of new equity are treated as a
direct reduction of proceeds. The share capital comprises only one
class of Ordinary share. Each Ordinary share carries an equal
voting right and right to a dividend.
Merger reserve
Merger reserve represents the difference between the market
value of shares issued to effect business combinations less the
nominal value of shares issued. The merger reserve in the Group
financial statements also includes the consolidation adjustments
that arise under the application of the pooling of interest method.
During the year the merger reserve was released to retained
earnings as the assets which gave rise to its original recognition
are now fully written down.
Retained earnings
Retained earnings contain the accumulated profits/(losses) of
the Group.
Share-based payments reserve
Equity-settled share-based payment transactions are measured at
the fair value of the services received, and the corresponding
increase in equity is recorded. EnQuest PLC shares held by the
Group in the Employee Benefit Trust are recognised at cost and are
deducted from the share-based payments reserve. Consideration
received for the sale of such shares is also recognised in equity,
with any difference between the proceeds from the sale and the
original cost being taken to reserves. No gain or loss is
recognised in the Group income statement on the purchase, sale,
issue or cancellation of equity shares.
Ordinary
shares
of GBP0.05 Share Share
each capital premium Total
Authorised, issued and fully paid Number $'000 $'000 $'000
---------------------------------- -------------- -------- -------- --------
At 1 January 2020 1,695,801,955 118,271 227,149 345,420
---------------------------------- -------------- -------- -------- --------
At 31 December 2020 1,695,801,955 118,271 227,149 345,420
---------------------------------- -------------- -------- -------- --------
At 31 December 2020, there were 46,492,546 shares held by the
Employee Benefit Trust (2018: 43,232,936). 9,562,007 shares were
purchased across 2020 to the Employee Benefit Trust with the
remaining movement in the year due to shares used to satisfy awards
made under the Company's share-based incentive schemes.
21. Share-based payment plans
Accounting policy
Eligible employees (including Directors) of the Group receive
remuneration in the form of share-based payment transactions,
whereby employees render services in exchange for shares or rights
over shares of EnQuest PLC.
The Directors of the Company have approved four share schemes
for the benefit of Directors and employees, being a Deferred Bonus
Share Plan, a Restricted Share Plan, a Performance Share Plan and a
Sharesave Plan.
The cost of these equity-settled transactions is measured by
reference to the fair value at the date on which they are granted.
The fair value of awards is calculated in reference to the scheme
rules at the market value, being the average middle market
quotation of a share for the three immediately preceding dealing
days as derived from the Daily Official List of the London Stock
Exchange, provided such dealing days do not fall within any period
when dealings in shares are prohibited because of any dealing
restriction. The fair values of awards granted to employees during
the year are based on the market value on the date of grant, or
date of invitation in respect to the Sharesave Plan.
The cost of equity-settled transactions is recognised over the
vesting period in which the relevant employees become fully
entitled to the award. The cumulative expense recognised for
equity-settled transactions at each reporting date until the
vesting date reflects the extent to which the vesting period has
expired and the Group's best estimate of the number of equity
instruments that will ultimately vest. The Group income statement
charge or credit for a period represents the movement in cumulative
expense recognised as at the beginning and end of that period.
In valuing the transactions, no account is taken of any service
or performance conditions, other than conditions linked to the
price of the shares of EnQuest PLC (market conditions) or
'non-vesting' conditions, if applicable. No expense is recognised
for awards that do not ultimately vest, except for awards where
vesting is conditional upon a market or non-vesting condition,
which are treated as vesting irrespective of whether or not the
market or non-vesting condition is satisfied, provided that all
other performance conditions are satisfied. Equity awards cancelled
are treated as vesting immediately on the date of cancellation, and
any expense not previously recognised for the award at that date is
recognised in the Group income statement.
The share-based payment expense recognised for each scheme was
as follows:
2020 2019
$'000 $'000
-------------------------------- ------ ------
Deferred Bonus Share Plan 95 303
-------------------------------- ------ ------
Restricted Share Plan 221 580
-------------------------------- ------ ------
Performance Share Plan 3,277 3,988
-------------------------------- ------ ------
Sharesave Plan (240) 858
-------------------------------- ------ ------
Executive Director bonus awards 48 159
-------------------------------- ------ ------
3,401 5,888
-------------------------------- ------ ------
The following disclosure and tables show the number of shares
potentially issuable under equity-settled employee share awards,
including the number of options outstanding and those options which
been exercised and are exercisable at the end of each year.
Deferred Bonus Share Plan ('DBSP')
Eligible employees are invited to participate in the DBSP
scheme. Participants may be invited to elect or, in some cases, be
required, to receive a proportion of any bonus in Ordinary shares
of EnQuest (invested awards). Following such award, EnQuest will
generally grant the participant an additional award over a number
of shares bearing a specified ratio to the number of invested
shares (matching shares). The awards granted will vest 33% on the
first anniversary of the date of grant, a further 33% after year
two and the final 34% on the third anniversary of the date of
grant. Awards, both invested and matching, are forfeited if the
employee leaves the Group before the awards vest.
The fair values of DBSP awards granted to employees during the
year, based on the defined market value on the date of grant, are
set out below:
2020 2019
-------------------------------------- ---- ----
Weighted average fair value per share 31p 36p
-------------------------------------- ---- ----
The following shows the movement in the number of share awards
held under the DBSP scheme:
2020 2019
Number Number
--------------------------- --------- -----------
Outstanding at 1 January 925,510 2,147,103
--------------------------- --------- -----------
Granted during the year - -
--------------------------- --------- -----------
Exercised during the year (705,683) (1,127,850)
--------------------------- --------- -----------
Forfeited during the year (58,989) (93,743)
--------------------------- --------- -----------
Outstanding at 31 December 160,838 925,510
--------------------------- --------- -----------
Exercisable at 31 December - -
--------------------------- --------- -----------
The weighted average contractual life for the share awards
outstanding as at 31 December 2020 was 0.3 years (2019: 0.6
years).
21. Share-based payment plans (continued)
Restricted Share Plan ('RSP')
Under the RSP scheme, employees are granted shares in EnQuest
over a discretionary vesting period at the discretion of the
Remuneration Committee of the Board of Directors of EnQuest, which
may or may not be subject to the satisfaction of performance
conditions. Awards made under the RSP will vest over periods
between one and four years. At present, there are no performance
conditions applying to this scheme nor is there currently any
intention to introduce them in the future.
The fair values of RSP awards granted to employees during the
year, based on the defined market value on the date of grant, are
set out below:
2020 2019
-------------------------------------- ---- ----
Weighted average fair value per share 24p 31p
-------------------------------------- ---- ----
The following table shows the movement in the number of share
awards held under the RSP scheme:
2020 2019
Number Number(ii)
--------------------------- ----------- -----------
Outstanding at 1 January 4,848,299 12,672,753
--------------------------- ----------- -----------
Granted during the year 399,089 45,303
--------------------------- ----------- -----------
Exercised during the year (2,229,196) (7,826,383)
--------------------------- ----------- -----------
Forfeited during the year (68,552) (43,374)
--------------------------- ----------- -----------
Outstanding at 31 December 2,949,640 4,848,299
--------------------------- ----------- -----------
Exercisable at 31 December 1,821,724 2,822,934
--------------------------- ----------- -----------
The weighted average contractual life for the share awards
outstanding as at 31 December 2020 was 2.1 years (2019: 2.6
years).
Performance Share Plan ('PSP')
PSP vesting is subject to performance conditions. PSP share
awards granted before 2020 had four sets of performance conditions
associated with them: 30% of the award relates to Total Shareholder
Return ('TSR') against a number of comparator group oil and gas
companies listed on the FTSE 350, AIM Top 100 and Stockholm NASDAQ
OMX; 30% relates to reduction in net debt; 30% relates to
production growth; and 10% relates to 2P reserve additions over the
three-year performance period. Awards will vest on the third
anniversary.
For 2020 the PSP share awards granted during the year have only
one performance condition, 100% of the award relates to Total
Shareholder Return ('TSR') against a number of comparator group oil
and gas companies listed on the FTSE 350, AIM Top 100 and Stockholm
NASDAQ OMX. Awards will vest on the third anniversary.
The fair values of PSP awards granted to employees during the
year, based on the defined market value on the date of grant and
which allow for the effect of the TSR condition which is a
market-based performance condition, are set out below:
2020 2019
-------------------------------------- ---- ----
Weighted average fair value per share 18p 27p
-------------------------------------- ---- ----
The following table shows the movement in the number of share
awards held under the PSP scheme:
2020 2019
Number Number
--------------------------- ------------ ------------
Outstanding at 1 January 69,637,698 77,898,199
--------------------------- ------------ ------------
Granted during the year 52,520,457 33,000,603
--------------------------- ------------ ------------
Exercised during the year (3,353,253) (19,644,786)
--------------------------- ------------ ------------
Forfeited during the year (13,919,026) (21,616,318)
--------------------------- ------------ ------------
Outstanding at 31 December 104,885,876 69,637,698
--------------------------- ------------ ------------
Exercisable at 31 December 8,248,209 3,852,953
--------------------------- ------------ ------------
The weighted average contractual life for the share awards
outstanding as at 31 December 2020 was 5.8 years (2019: 6.3
years).
21. Share-based payment plans (continued)
Sharesave Plan
The Group operates an approved savings-related share option
scheme. The plan is based on eligible employees being granted
options and their agreement to opening a Sharesave account with a
nominated savings carrier and to save over a specified period,
either three or five years. The right to exercise the option is at
the employee's discretion at the end of the period previously
chosen, for a period of six months.
The fair values of Sharesave awards granted to employees during
the year, based on the defined market value on the date the
invitation for the scheme opens, are shown below:
2020 2019
-------------------------------------- ---- ----
Weighted average fair value per share 12p 22p
-------------------------------------- ---- ----
The following shows the movement in the number of share options
held under the Sharesave Plan:
2020 2019
Number Number
--------------------------- ------------ ------------
Outstanding at 1 January 42,589,522 35,747,677
--------------------------- ------------ ------------
Granted during the year 34,719,941 39,101,971
--------------------------- ------------ ------------
Exercised during the year (452,545) (6,385,608)
--------------------------- ------------ ------------
Forfeited during the year (34,473,264) (25,874,518)
--------------------------- ------------ ------------
Outstanding at 31 December 42,383,654 42,589,522
--------------------------- ------------ ------------
Exercisable at 31 December 449,912 2,879,900
--------------------------- ------------ ------------
The weighted average contractual life for the share options
outstanding as at 31 December 2020 was 2.6 years (2019: 2.8
years).
Executive Director bonus awards
As detailed in the Directors' Remuneration Report, the
remuneration of the Executive Directors includes the participation
in an annual bonus plan. Any bonus amount in excess of 100% of
salary will be deferred into EnQuest shares for two years, subject
to continued employment.
The fair value of the Executive Director bonus awards granted
during the year, based on the defined market value on the date of
grant, are set out below:
2020 2019
-------------------------------------- ---- ----
Weighted average fair value per share 15p 28p
-------------------------------------- ---- ----
The following table shows the movement in the number of share
awards held under the Executive Director bonus plan:
2020 2019
Number Number
--------------------------- ---------- -----------
Outstanding at 1 January 1,963,454 3,159,786
--------------------------- ---------- -----------
Granted during the year 303,862 138,483
--------------------------- ---------- -----------
Exercised during the year - (1,334,815)
--------------------------- ---------- -----------
Outstanding at 31 December 2,267,316 1,963,454
--------------------------- ---------- -----------
Exercisable at 31 December 1,824,971 1,526,678
--------------------------- ---------- -----------
The weighted average contractual life for the share awards
outstanding as at 31 December 2020 was 1.3 years (2019: 0.6
years).
22. Contingent consideration
Accounting policy
When the consideration transferred by the Group in a business
combination includes a contingent consideration arrangement, the
contingent consideration is measured at its acquisition-date fair
value and included as part of the consideration transferred in a
business combination. Changes in fair value of the contingent
consideration that qualify as measurement period adjustments are
adjusted retrospectively, with corresponding adjustments against
goodwill. Measurement period adjustments are adjustments that arise
from additional information obtained during the 'measurement
period' (which cannot exceed one year from the acquisition date)
about facts and circumstances that existed at the acquisition
date.
The subsequent accounting for changes in the fair value of the
contingent consideration that do not qualify as measurement period
adjustments depends on how the contingent consideration is
classified. Contingent consideration that is classified as equity
is not remeasured at subsequent reporting dates and its subsequent
settlement is accounted for within equity. Other contingent
consideration is remeasured to fair value at subsequent reporting
dates with changes in fair value recognised in profit or loss.
Magnus
Magnus decommissioning-linked
75% liability Total
$'000 $'000 $'000
------------------------------------- ---------- ----------------------------- ----------
At 31 December 2019 641,400 15,861 657,261
------------------------------------- ---------- ----------------------------- ----------
Change in fair value (see note 5(d)) (137,356) (893) (138,249)
------------------------------------- ---------- ----------------------------- ----------
Unwinding of discount (see note 6) 64,140 1,586 65,726
------------------------------------- ---------- ----------------------------- ----------
Interest on vendor loan (see note 6) 11,533 - 11,533
------------------------------------- ---------- ----------------------------- ----------
Utilisation (72,056) (1,954) (74,010)
------------------------------------- ---------- ----------------------------- ----------
At 31 December 2020 507,661 14,600 522,261
------------------------------------- ---------- ----------------------------- ----------
Classified as:
------------------------------------- ---------- ----------------------------- ----------
Current 73,676 201 73,877
------------------------------------- ---------- ----------------------------- ----------
Non-current 433,984 14,400 448,384
------------------------------------- ---------- ----------------------------- ----------
507,660 14,601 522,261
------------------------------------- ---------- ----------------------------- ----------
75% Magnus acquisition contingent consideration
On 1 December 2018, EnQuest completed the acquisition of the
additional 75% interest in the Magnus oil field ('Magnus') and
associated interests (collectively the 'Transaction assets') which
was part funded through a vendor loan and profit share arrangement
with BP. This acquisition followed on from the acquisition of
initial interests completed in December 2017.
The consideration for the acquisition was $300.0 million,
consisting of $100.0 million cash contribution, paid from the funds
received through the rights issue undertaken in October 2018, and
$200.0 million deferred consideration financed by BP. The deferred
consideration, which is repayable solely out of cash flows which
are in excess of operating cash flows from Magnus, is secured over
the interests in the Transaction assets and accrues interest at a
rate of 7.5% per annum on the deferred consideration. The
consideration also included a contingent profit-sharing arrangement
whereby EnQuest and BP share the net cash flow generated by the 75%
interest on a 50:50 basis, subject to a cap of $1 billion received
by BP. Together, the deferred consideration and contingent
profit-sharing arrangement are known as contingent
consideration.
The contingent consideration is a financial liability classified
as measured at fair value through profit or loss. The fair value of
contingent consideration has been determined by calculating the
present value of the future expected cash flows expected to be paid
and is considered a level 3 valuation under the fair value
hierarchy. Future cash flows are estimated based on inputs
including future oil prices, production volumes, and operating
costs. The discount rate assumption and other inputs are detailed
in note 2. The contingent consideration was fair valued at 31
December 2020, which resulted in a decrease in fair value of $137.4
million (2019: increase $13.5 million), reflecting the change in
oil price assumptions. The fair value accounting effect and finance
costs of $77.3 million (2019: $55.0 million) on the contingent
consideration were recognised through remeasurements and
exceptional items in the Group income statement. The contingent
profit sharing arrangement cap of $1 billion was not met in 2020 in
the present value calculations (2019: cap was met). Within the
statement of cash flows the profit share element of the repayment,
$41.1 million (2019: $21.6 million) is disclosed separately under
investing activities; the repayment of the vendor loan, $20.7
million (2019: $17.9 million) is disclosed under financing
activities; and the interest paid on the vendor loan, $10.3 million
(2019: $14.2 million) is included within Interest paid under
financing activities. At 31 December 2020, the contingent
consideration was $507.7million (31 December 2019: $641.4
million).
Management has considered alternative scenarios to assess the
valuation of the contingent consideration including, but not
limited to, the key accounting estimate relating to oil price and
the interrelationship with production and the profit share
arrangement. As detailed in key accounting estimates, a reduction
or increase in the price assumptions of 10% are considered to be
reasonably possible changes, resulting in a reduction of $91.7
million or an increase of $91.7 million to the contingent
consideration, respectively (2019: reduction of $97.8 million and
increase of $54.3 million, respectively). The change in value
represents a change in timing of cash flows, with the contingent
profit sharing arrangement cap of $1 billion not met in either
sensitivity.
The payment of contingent consideration is limited to cash flows
generated from Magnus. Therefore, no contingent consideration is
payable if insufficient cash flows are generated over and above the
requirements to operate the asset. By reference to the conditions
existing at 31 December 2020, the maturity analysis of the loan is
disclosed in Risk management and financial instruments - liquidity
risk (note 27).
Magnus decommissioning-linked contingent consideration
As part of the Magnus and associated interests acquisition, BP
retained the decommissioning liability in respect of the existing
wells and infrastructure and EnQuest agreed to pay additional
consideration in relation to the management of the physical
decommissioning costs of Magnus. At 31 December 2020, the amount
due to BP calculated on an after-tax basis by reference to 30% of
BP's decommissioning costs on Magnus was $14.6 million (2019: $15.9
million).
23. Provisions
Accounting policy
Decommissioning
Provision for future decommissioning costs is made in full when
the Group has an obligation: to dismantle and remove a facility or
an item of plant; to restore the site on which it is located; and
when a reasonable estimate of that liability can be made. The
Group's provision primarily relates to the future decommissioning
of production facilities and pipelines.
A decommissioning asset and liability are recognised, within
property plant and equipment and provisions respectively, at the
present value of the estimated future decommissioning costs. The
decommissioning asset is amortised over the life of the underlying
asset on a unit of production basis over proven and probable
reserves, included within depletion in the Group income statement.
Any change in the present value of estimated future decommissioning
costs is reflected as an adjustment to the provision and the oil
and gas asset. The unwinding of the decommissioning liability is
included under finance costs in the Group income statement.
These provisions have been created based on internal and
third-party estimates. Assumptions based on the current economic
environment have been made which management believe are a
reasonable basis upon which to estimate the future liability. These
estimates are reviewed regularly to take into account any material
changes to the assumptions. However, actual decommissioning costs
will ultimately depend upon future market prices for the necessary
decommissioning works required, which will reflect market
conditions at the relevant time. Furthermore, the timing of
decommissioning liabilities is likely to depend on the dates when
the fields cease to be economically viable. This in turn depends on
future oil prices, which are inherently uncertain. See 'Key sources
of estimation uncertainty' - Decommissioning provision in note
2.
Other
Provisions are recognised when the Group has a present legal or
constructive obligation as a result of past events; it is probable
that an outflow of resources will be required to settle the
obligation; and a reliable estimate can be made of the amount of
the obligation.
Thistle
Decommissioning decommissioning Other
provision provision provisions Total
$'000 $'000 $'000 $'000
-------------------------- --------------- ---------------- ----------- --------
At 31 December 2019 711,898 39,811 11,250 762,959
-------------------------- --------------- ---------------- ----------- --------
Additions during the year 7,462 - 9,137 16,599
-------------------------- --------------- ---------------- ----------- --------
Changes in estimates 85,937 11,998 - 97,935
-------------------------- --------------- ---------------- ----------- --------
Unwinding of discount 14,512 796 - 15,308
-------------------------- --------------- ---------------- ----------- --------
Utilisation (41,605) - (11,250) (52,855)
-------------------------- --------------- ---------------- ----------- --------
Foreign exchange - 461 - 461
-------------------------- --------------- ---------------- ----------- --------
At 31 December 2020 778,204 53,066 9,137 840,407
-------------------------- --------------- ---------------- ----------- --------
Classified as:
-------------------------- --------------- ---------------- ----------- --------
Current 68,805 21,012 9,137 98,954
-------------------------- --------------- ---------------- ----------- --------
Non-current 709,399 32,054 - 741,453
-------------------------- --------------- ---------------- ----------- --------
778,204 53,066 9,137 840,407
-------------------------- --------------- ---------------- ----------- --------
Decommissioning provision
The Group's total provision represents the present value of
decommissioning costs which are expected to be incurred up to 2048,
assuming no further development of the Group's assets. At 31
December 2020, an estimated $329.2 million is expected to be
utilised between one and five years (2019: $155.6 million), $145.1
million within six to ten years (2019: $339.8 million), and the
remainder in later periods.
As described in the accounting policy above, the decommissioning
provision estimates are highly dependent on future events.
Sensitivities have been run on the discount rate assumption (see
note 2), with a 0.5% change being considered to be a reasonable
possible change, resulting in an approximate reduction and increase
of $35.4 million and $38.4 million (2019: $34.7 million and $31.8
million), respectively.
The Group enters into surety bonds principally to provide
security for its decommissioning obligations. The surety bond
facilities which expired in December 2020 were renewed for 12
months, subject to ongoing compliance with the terms of the Group's
borrowings. At 31 December 2020, the Group held surety bonds
totalling $151.7 million (2019: $131.6 million).
Thistle decommissioning provision
In 2017, EnQuest had the option to receive $50.0 million from BP
in exchange for undertaking the management of the physical
decommissioning activities for Thistle and Deveron and making
payments by reference to 7.5% of BP's share of decommissioning
costs of Thistle and Deveron fields. The option was exercised in
full during 2018 and the liability recognised within provisions. At
31 December 2020, the amount due to BP by reference to 7.5% of BP's
decommissioning costs on Thistle and Deveron was $53.1 million
(2019: $39.8 million). Unwinding of discount of $0.8 million is
included within finance income for the year ended 31 December 2020
(2019: $0.9 million).
Other provisions
During 2019, the Group finalised and settled the historical
breach of warranty claims with KUFPEC, the Group's field partner in
respect of Alma/Galia. The settlement completed all outstanding
claims and a provision of $22.5 million was recognised for the
payments to be made to KUFPEC. A total of $6.9 million had been
provided in 2019, resulting in the remaining $15.6 million being
taken to the Group income statement through remeasurements and
exceptional items. A total of $11.3 million was paid during 2020
(2019: $11.2 million) fully utilising the provision.
During 2020, a riser at the Seligi Alpha platform which provides
gas lift and injection to the Seligi Bravo platform detached
resulting in a release of gas and a subsequent fire. At 31 December
2020 the Group has provided $5.9 million with respect to required
repairs to remedy the damage caused. The Group expects to complete
the repairs during 2021.
Other provisions also include redundancy provision of $1.2
million in relation to the transformation programme undertaken
during 2020 and $1.5 million in relation to the payment of
partners' share of pipeline oil stock following cessation of
production at Heather.
24. Leases
Accounting policy
As a lessee
The Group recognises a right-of-use asset and a lease liability
at the lease commencement date.
The lease liability is initially measured at the present value
of the lease payments that are not paid at the commencement date,
discounted by using the rate implicit in the lease, or, if that
rate cannot be readily determined, the Group uses its incremental
borrowing rate.
The incremental borrowing rate is the rate that the Group would
have to pay for a loan of a similar term, and with similar
security, to obtain an asset of similar value. The incremental
borrowing rate is determined based on a series of inputs including:
the term, the risk-free rate based on government bond rates and a
credit risk adjustment based on EnQuest bond yields.
Lease payments included in the measurement of the lease
liability comprise:
-- fixed lease payments (including in-substance fixed payments), less any lease incentives;
-- variable lease payments that depend on an index or rate,
initially measured using the index or rate at the commencement
date;
-- the exercise price of purchase options, if the lessee is
reasonably certain to exercise the options; and
-- payments of penalties for terminating the lease, if the lease
term reflects the exercise of an option to terminate the lease.
The lease liability is subsequently recorded at amortised cost,
using the effective interest rate method. The liability is
remeasured when there is a change in future lease payments arising
from a change in an index or rate or if the Group changes its
assessment of whether it will exercise a purchase, extension or
termination option. When the lease liability is remeasured in this
way, a corresponding adjustment is made to the carrying amount of
the right-of-use asset, or is recorded in profit or loss if the
carrying amount of the right-of-use asset has been reduced to zero.
The Group did not make any such adjustments during the periods
presented.
The right-of-use asset is measured at cost, which comprises the
initial amount of the lease liability adjusted for any lease
payments made at or before the commencement date, plus any initial
direct costs incurred and an estimate of costs to dismantle and
remove the underlying asset or to restore the underlying asset or
the site on which it is located, less any lease incentives
received. Right-of-use assets are depreciated over the shorter
period of lease term and useful life of the underlying asset. If a
lease transfers ownership of the underlying asset or the cost of
the right-of-use asset reflects that the Group expects to exercise
a purchase option, the related right-of-use asset is depreciated
over the useful life of the underlying asset. The depreciation
starts at the commencement date of the lease.
The Group applies the short-term lease recognition exemption to
those leases that have a lease term of 12 months or less from the
commencement date. It also applies the low-value assets recognition
exemption to leases of assets below GBP5,000. Lease payments on
short-term leases and leases of low-value assets are recognised as
an expense on a straight-line basis over the lease term.
The Group applies IAS 36 Impairment of Assets to determine
whether a right-of-use asset is impaired and accounts for any
identified impairment loss as described in the 'property, plant and
equipment' policy.
Variable rents that do not depend on an index or rate are not
included in the measurement of the lease liability and the
right-of-use asset. The related payments are recognised as an
expense in the period in which the event or condition that triggers
those payments occurs and are included within 'cost of sales' or
'general and administration expenses' in the Group income
statement.
For leases within joint ventures, the Group assesses on a
lease-by-lease basis the facts and circumstances. This relates
mainly to leases of vessels. Where all parties to a joint operation
jointly have the right to control the use of the identified asset
and all parties have a legal obligation to make lease payments to
the lessor, the Group's share of the right-of-use asset and its
share of the lease liability will be recognised on the Group
balance sheet. This may arise in cases where the lease is signed by
all parties to the joint operation or the joint operation partners
are named within the lease. However, in cases where EnQuest is the
only party with the legal obligation to make lease payments to the
lessor, the full lease liability and right-of-use asset will be
recognised on the Group balance sheet. This may be the case if, for
example, EnQuest, as operator of the joint operation, is the sole
signatory to the lease. If the underlying asset is used for the
performance of the joint operation agreement, EnQuest will recharge
the associated costs in line with joint operating agreement.
As a lessor
When the Group acts as a lessor, it determines at lease
inception whether each lease is a finance lease or an operating
lease. Whenever the terms of the lease transfer substantially all
the risks and rewards of ownership to the lessee, the contract is
classified as a finance lease. All other leases are classified as
operating leases.
When the Group is an intermediate lessor, it accounts for the
head-lease and the sub-lease as two separate contracts. The
sub-lease is classified as a finance or operating lease by
reference to the right-of-use asset arising from the
head-lease.
Rental income from operating leases is recognised on a
straight-line basis over the term of the relevant lease. Initial
direct costs incurred in negotiating and arranging an operating
lease are added to the carrying amount of the leased asset and
recognised on a straight-line basis over the lease term.
Amounts due from lessees under finance leases are recognised as
receivables at the amount of the Group's net investment in the
leases. Finance lease income is allocated to reporting periods so
as to reflect a constant periodic rate of return on the Group's net
investment outstanding in respect of the leases.
When a contract includes lease and non-lease components, the
Group applies IFRS 15 to allocate the consideration under the
contract to each component.
24. Leases (continued)
Right-of-use assets and lease liabilities
Set out below are the carrying amounts of the Group's
right-of-use assets and lease liabilities and the movements during
the period:
Right-of-use Lease
assets liabilities
$'000 $'000
-------------------------------------- ------------ ------------
As at 31 December 2018 - 708,950
-------------------------------------- ------------ ------------
Finance lease reclassification 690,742 -
-------------------------------------- ------------ ------------
IFRS 16 recognition adjustment 60,527 60,527
-------------------------------------- ------------ ------------
Additions in the period 24,587 24,587
-------------------------------------- ------------ ------------
Depreciation expense (90,657) -
-------------------------------------- ------------ ------------
Interest expense - 55,686
-------------------------------------- ------------ ------------
Payments - (135,125)
-------------------------------------- ------------ ------------
Foreign exchange movements - 1,541
-------------------------------------- ------------ ------------
As at 31 December 2019 685,199 716,166
-------------------------------------- ------------ ------------
Additions in the period (see note 10) 2,812 2,812
-------------------------------------- ------------ ------------
Depreciation expense (see note 10) (82,703) -
-------------------------------------- ------------ ------------
Impairment (see note 10) (108,160) -
-------------------------------------- ------------ ------------
Disposal (706) (726)
-------------------------------------- ------------ ------------
Interest expense - 50,851
-------------------------------------- ------------ ------------
Payments - (123,001)
-------------------------------------- ------------ ------------
Foreign exchange movements - 1,744
-------------------------------------- ------------ ------------
As at 31 December 2020 496,442 647,846
-------------------------------------- ------------ ------------
Current 99,439
-------------------------------------- ------------ ------------
Non-current 548,407
-------------------------------------- ------------ ------------
647,846
-------------------------------------- ------------ ------------
The Group leases assets including the Kraken FPSO, property and
oil and gas vessels, with a weighted average lease term of six
years. The maturity analysis of lease liabilities are disclosed in
note 27.
Amounts recognised in profit or loss
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
-------------------------------------------- ------------ ------------
Depreciation expense of right-of-use assets 82,703 90,657
-------------------------------------------- ------------ ------------
Interest expense on lease liabilities 50,851 55,689
-------------------------------------------- ------------ ------------
Rent expense - short-term leases 12,736 2,646
-------------------------------------------- ------------ ------------
Rent expense - leases of low-value assets 43 28
-------------------------------------------- ------------ ------------
Total amounts recognised in profit or loss 146,333 149,020
-------------------------------------------- ------------ ------------
Amounts recognised in statement of cash flows
Year ended Year ended
31 December 31 December
2020 2019
$'000 $'000
------------------------------ ------------ ------------
Total cash outflow for leases 123,001 135,125
------------------------------ ------------ ------------
Leases as lessor
The Group sub-leases part of Annan House, the Aberdeen office.
The sub-lease is classified as an operating lease, as all the risks
and rewards incidental to the ownership of the right-of-use asset
are not all substantially transferred to the lessee. Rental income
recognised by the Group during 2020 was $1.7 million (2019: $1.3
million).
The following table sets out a maturity analysis of lease
payments, showing the undiscounted lease payments to be received
after the reporting date:
2020 2019
$'000 $'000
---------------------------------- ------- ------
Less than one year 2,211 1,635
---------------------------------- ------- ------
One to two years 2,211 1,762
---------------------------------- ------- ------
Two to three years 2,211 1,762
---------------------------------- ------- ------
Three to four years 2,211 1,762
---------------------------------- ------- ------
Four to five years 1,508 1,762
---------------------------------- ------- ------
More than five years 8,497 1,147
---------------------------------- ------- ------
Total undiscounted lease payments 18,849 9,830
---------------------------------- ------- ------
25. Commitments and contingencies
Capital commitments
At 31 December 2020, the Group had capital commitments amounting
to nil (2019: $17.9 million).
Other commitments
In the normal course of business, the Group will obtain surety
bonds, letters of credit and guarantees. At 31 December 2020, the
Group held surety bonds totalling $151.7 million (2019: 131.6
million) to provide security for its decommissioning obligations.
See note 23 for further details.
Contingencies
The Group becomes involved from time to time in various claims
and lawsuits arising in the ordinary course of its business. The
Company is not, nor has been during the past 12 months, involved in
any governmental, legal or arbitration proceedings which, either
individually or in the aggregate, have had, or are expected to
have, a material adverse effect on the Company's and/or the Group
balance sheet or profitability, nor, so far as the Company is
aware, are any such proceedings pending or threatened.
26. Related party transactions
The Group financial statements include the financial statements
of EnQuest PLC and its subsidiaries. A list of the Group's
principal subsidiaries is contained in note 28 to these Group
financial statements.
Balances and transactions between the Company and its
subsidiaries, which are related parties, have been eliminated on
consolidation and are not disclosed in this note.
All sales to and purchases from related parties are made at
normal market prices and the pricing policies and terms of these
transactions are approved by the Group's management. With the
exception of the transactions disclosed below, there have been no
transactions with related parties who are not members of the Group
during the year ended 31 December 2020 (2019: none).
Office sub-lease
During the year ended 31 December 2020, the Group recognised
$0.1 million (2019: $0.1 million) of rental income in respect of an
office sub-lease arrangement with Levendi Investment Management
Limited, a company where 72% of the issued share capital is held by
Amjad Bseisu.
Compensation of key management personnel
The following table details remuneration of key management
personnel of the Group. Key management personnel comprise of
Executive and Non-Executive Directors of the Company and the
Executive Committee.
2020 2019
$'000 $'000
--------------------------------- ------ ------
Short-term employee benefits 7,576 7,584
--------------------------------- ------ ------
Share-based payments 107 1,245
--------------------------------- ------ ------
Post-employment pension benefits 224 199
--------------------------------- ------ ------
7,907 9,028
--------------------------------- ------ ------
27. Risk management and financial instruments
Risk management objectives and policies
The Group's principal financial assets and liabilities comprise
trade and other receivables, cash and short-term deposits,
interest-bearing loans, borrowings and finance leases, derivative
financial instruments and trade and other payables. The main
purpose of the financial instruments is to manage short-term cash
flow and raise finance for the Group's capital expenditure
programme.
The Group's activities expose it to various financial risks
particularly associated with fluctuations in oil price, foreign
currency risk, liquidity risk and credit risk. Management reviews
and agrees policies for managing each of these risks, which are
summarised below. Also presented below is a sensitivity analysis to
indicate sensitivity to changes in market variables on the Group's
financial instruments and to show the impact on profit and
shareholders' equity, where applicable. The sensitivity has been
prepared for periods ended 31 December 2020 and 2019, using the
amounts of debt and other financial assets and liabilities held at
those reporting dates.
Commodity price risk - oil prices
The Group is exposed to the impact of changes in Brent oil
prices on its revenues and profits generated from sales of crude
oil.
The Group's policy is to have the ability to hedge oil prices up
to a maximum of 75% of the next 12 months' production on a rolling
annual basis, up to 60% in the following 12-month period and 50% in
the subsequent 12-month period.
Details of the commodity derivative contracts entered into
during and open at the end of 2020 are disclosed in note 19. As of
31 December 2020, the Group held financial instruments (options and
swaps) related to crude oil that covered 1.0 MMbbls of 2021
production. The instruments have an effective an average floor
price of around $48.9/bbl in 2021. The group utilises multiple
benchmarks when hedging production to achieve optimal results for
the Group. No derivatives were designated in hedging relationships
at 31 December 2020.
The following table summarises the impact on the Group's pre-tax
profit of a reasonably possible change in the Brent oil price, on
the fair value of derivative financial instruments, with all other
variables held constant. The impact in equity is the same as the
impact on profit before tax.
Pre-tax profit
----------------- --------------------
+$10/bbl -$10/bbl
increase decrease
$'000 $'000
----------------- --------- ---------
31 December 2020 (8,020) 1,365
----------------- --------- ---------
31 December 2019 (22,894) 20,500
----------------- --------- ---------
27. Risk management and financial instruments (continued)
Foreign exchange risk
The Group is exposed to foreign exchange risk arising from
movements in currency exchange rates. Such exposure arises from
sales or purchases in currencies other than the Group's functional
currency and the retail bond which is denominated in Sterling. To
mitigate the risks of large fluctuations in the currency markets,
the hedging policy agreed by the Board allows for up to 70% of the
non-US Dollar portion of the Group's annual capital budget and
operating expenditure to be hedged. For specific contracted capital
expenditure projects, up to 100% can be hedged. Approximately 8%
(2019: 6%) of the Group's sales and 86% (2019: 95%) of costs
(including operating and capital expenditure and general and
administration costs) are denominated in currencies other than the
functional currency.
The Group also enters into foreign currency swap contracts from
time to time to manage short-term exposures. The following tables
summarise the Group's financial assets and liabilities exposure to
foreign currency.
GBP MYR Other Total
Year ended 31 December 2020 $'000 $'000 $'000 $'000
---------------------------- ------- ------ ------ -------
Total Financial Assets 32,150 11,735 2,777 46,662
----------------------------- ------- ------ ------ -------
Total Financial Liabilities 519,060 23,931 869 543,860
----------------------------- ------- ------ ------ -------
GBP MYR Other Total
Year ended 31 December 2019 $'000 $'000 $'000 $'000
---------------------------- ------- ------- ------ -------
Total Financial Assets 136,158 28,421 4,195 168,774
----------------------------- ------- ------- ------ -------
Total Financial Liabilities 637,042 113,901 3,091 754,034
----------------------------- ------- ------- ------ -------
The following table summarises the sensitivity to a reasonably
possible change in the US Dollar to Sterling foreign exchange rate,
with all other variables held constant, of the Group's profit
before tax due to changes in the carrying value of monetary assets
and liabilities at the reporting date. The impact in equity is the
same as the impact on profit before tax. The Group's exposure to
foreign currency changes for all other currencies is not
material:
Pre-tax profit
----------------- ------------------------------
+$10% -$10%
rate increase rate decrease
$'000 $'000
----------------- -------------- --------------
31 December 2020 (46,183) 46,183
----------------- -------------- --------------
31 December 2019 (47,158) 47,158
----------------- -------------- --------------
Credit risk
Credit risk is managed on a Group basis. Credit risk in
financial instruments arises from cash and cash equivalents and
derivative financial instruments where the Group's exposure arises
from default of the counterparty, with a maximum exposure equal to
the carrying amount of these instruments. For banks and financial
institutions, only those rated with an A-/A3 credit rating or
better are accepted. Cash balances can be invested in short-term
bank deposits and AAA-rated liquidity funds, subject to
Board-approved limits and with a view to minimising counterparty
credit risks.
In addition, there are credit risks of commercial counterparties
including exposures in respect of outstanding receivables. The
Group trades only with recognised international oil and gas
companies, commodity traders and shipping companies and at 31
December 2020 there were $2.6 million of trade receivables past due
(2019: $2.4 million), $2.5 million of joint venture receivables
past due (2019: $0.1 million) but not impaired. Subsequent to year
end, $4.4 million of these outstanding balances have been collected
(2019: $2.4 million). Receivable balances are monitored on an
ongoing basis with appropriate follow-up action taken where
necessary. The impact of ECL is disclosed in note 16.
2020 2019
Ageing of past due but not impaired receivables $'000 $'000
------------------------------------------------ ------ ------
Less than 30 days 2,974 381
------------------------------------------------ ------ ------
30-60 days 1,335 60
------------------------------------------------ ------ ------
60-90 days 164 -
------------------------------------------------ ------ ------
90-120 days 271 8
------------------------------------------------ ------ ------
120+ days 383 2,056
------------------------------------------------ ------ ------
5,127 2,505
------------------------------------------------ ------ ------
At 31 December 2020, the Group had three customers accounting
for 77% of outstanding trade receivables (2019: four customers,
84%) and one joint venture partners accounting for 16% of
outstanding joint venture receivables (2019: two joint venture
partners, 26%).
27. Risk management and financial instruments (continued)
Liquidity risk
The Group monitors its risk to a shortage of funds by reviewing
its cash flow requirements on a regular basis relative to its
existing bank facilities and the maturity profile of its
borrowings. Specifically, the Group's policy is to ensure that
sufficient liquidity or committed facilities exist within the Group
to meet its operational funding requirements and to ensure the
Group can service its debt and adhere to its financial covenants.
At 31 December 2020, $61.2 million (2019: $68.2million) was
available for drawdown under the Group's credit facilities (see
note 18).
The following tables detail the maturity profiles of the Group's
non-derivative financial liabilities including projected interest
thereon. The amounts in these tables are different from the balance
sheet as the table is prepared on a contractual undiscounted cash
flow basis and includes future interest payments.
The payment of contingent consideration is limited to cash flows
generated from Magnus (see note 22). Therefore, no contingent
consideration is payable if insufficient cash flows are generated
over and above the requirements to operate the asset and there is
no exposure to liquidity risk. By reference to the conditions
existing at the reporting period end, the maturity analysis of the
loan is disclosed below. All of the Groups liabilities are
unsecured.
Up to 1 to 2 2 to 5 Over 5
On demand 1 year years years years Total
Year ended 31 December 2020 $'000 $'000 $'000 $'000 $'000 $'000
--------------------------------- --------- -------- -------- ---------- -------- ----------
Loans and borrowings - 430,289 39,778 - - 470,067
--------------------------------- --------- -------- -------- ---------- -------- ----------
Bonds(i) - - - 1,255,474 - 1,255,474
--------------------------------- --------- -------- -------- ---------- -------- ----------
Contingent considerations - 78,219 77,055 254,319 401,259 810,852
--------------------------------- --------- -------- -------- ---------- -------- ----------
Obligations under finance leases
(IFRS 16) - 133,765 130,667 337,177 217,013 818,622
--------------------------------- --------- -------- -------- ---------- -------- ----------
Trade and other payables - 249,111 117 - - 249,228
--------------------------------- --------- -------- -------- ---------- -------- ----------
- 891,384 247,617 1,846,970 618,272 3,604,243
--------------------------------- --------- -------- -------- ---------- -------- ----------
Up to 1 to 2 2 to 5 Over 5
On demand 1 year years years years Total
Year ended 31 December 2019 $'000 $'000 $'000 $'000 $'000 $'000
--------------------------------- --------- -------- -------- ---------- ------- ---------
Loans and borrowings - 228,991 527,419 4,121 - 760,531
--------------------------------- --------- -------- -------- ---------- ------- ---------
Bonds(i) - 67,545 67,545 1,035,022 - 1,170,112
--------------------------------- --------- -------- -------- ---------- ------- ---------
Contingent considerations - 114,152 89,607 266,563 621,929 1,092,251
--------------------------------- --------- -------- -------- ---------- ------- ---------
Obligations under finance leases
(IFRS 16) - 152,306 132,294 350,492 281,915 917,007
--------------------------------- --------- -------- -------- ---------- ------- ---------
Trade and other payables - 326,035 - - 46,763 372,798
--------------------------------- --------- -------- -------- ---------- ------- ---------
- 889,029 816,865 1,656,198 950,607 4,312,699
--------------------------------- --------- -------- -------- ---------- ------- ---------
(i) Maturity analysis profile for the Group's bonds includes
semi-annual coupon interest. This interest is only payable in cash
if the average dated Brent oil price is equal to or greater than
$65/bbl for the six months preceding one month before the coupon
payment date (see note 18)
The following tables detail the Group's expected maturity of
payables and receivables for its derivative financial instruments.
The amounts in these tables are different from the balance sheet as
the table is prepared on a contractual undiscounted cash flow
basis. When the amount receivable or payable is not fixed, the
amount disclosed has been determined by reference to a projected
forward curve at the reporting date.
Less than 3 to 12 1 to 2 Over 2
On demand 3 months months years years Total
Year ended 31 December 2020 $'000 $'000 $'000 $'000 $'000 $'000
------------------------------- --------- --------- ------- ------ ------ ------
Commodity derivative contracts 3,108 2,007 - - - 5,115
------------------------------- --------- --------- ------- ------ ------ ------
3,108 2,007 - - - 5,115
------------------------------- --------- --------- ------- ------ ------ ------
Less than 3 to 12 1 to 2 Over 2
On demand 3 months months years years Total
Year ended 31 December 2019 $'000 $'000 $'000 $'000 $'000 $'000
-------------------------------------- --------- --------- ------- ------ ------ -------
Commodity derivative contracts 1,849 6,398 4,387 - - 12,634
-------------------------------------- --------- --------- ------- ------ ------ -------
Foreign exchange derivative contracts - (1,932) - - - (1,932)
-------------------------------------- --------- --------- ------- ------ ------ -------
1,849 4,466 4,387 - - 10,702
-------------------------------------- --------- --------- ------- ------ ------ -------
27. Risk management and financial instruments (continued)
Capital management
The capital structure of the Group consists of debt, which
includes the borrowings disclosed in note 18, cash and cash
equivalents and equity attributable to the equity holders of the
parent company, comprising issued capital, reserves and retained
earnings as in the Group statement of changes in equity.
The primary objective of the Group's capital management is to
optimise the return on investment, by managing its capital
structure to achieve capital efficiency whilst also maintaining
flexibility. The Group regularly monitors the capital requirements
of the business over the short, medium and long term, in order to
enable it to foresee when additional capital will be required.
The Group has approval from the Board to hedge foreign exchange
risk on up to 70% of the non-US Dollar portion of the Group's
annual capital budget and operating expenditure. For specific
contracted capex projects, up to 100% can be hedged. In addition,
the Group's policy is to have the ability to hedge oil prices up to
a maximum of 75% of the next 12 months' production on a rolling
annual basis, up to 60% in the following 12-month period and 50% in
the subsequent 12-month period. This is designed to reduce the risk
of adverse movements in exchange rates and market prices eroding
the return on the Group's projects and operations.
The Board regularly reassesses the existing dividend policy to
ensure that shareholder value is maximised. Any future payment of
dividends is expected to depend on the earnings and financial
condition of the Company and such other factors as the Board
considers appropriate.
The Group monitors capital using the gearing ratio and return on
shareholders' equity as follows. Further information relating to
the movement year-on-year is provided within the relevant notes and
within the Financial Review (pages 10 to 16).
2020 2019
$'000 $'000
---------------------------------------------------------- ---------- ---------
Loans, borrowings and bond(i) (A) (see note 18) 1,502,564 1,633,441
---------------------------------------------------------- ---------- ---------
Cash and short-term deposits (see note 14) (222,830) (220,456)
---------------------------------------------------------- ---------- ---------
Net debt (B) 1,279,734 1,412,985
---------------------------------------------------------- ---------- ---------
Equity attributable to EnQuest PLC shareholders (C) (207,377) 559,061
---------------------------------------------------------- ---------- ---------
Profit/(loss) for the year attributable to EnQuest PLC
shareholders (D) (768,539) (449,301)
---------------------------------------------------------- ---------- ---------
Profit/(loss) for the year attributable to EnQuest PLC
shareholders excluding exceptionals (E) (28,319) 214,340
---------------------------------------------------------- ---------- ---------
Gross gearing ratio (A/C) n/a 2.9
---------------------------------------------------------- ---------- ---------
Net gearing ratio (B/C) n/a 2.5
---------------------------------------------------------- ---------- ---------
Shareholders' return on investment (D/C) n/a n/a
---------------------------------------------------------- ---------- ---------
Shareholders' return on investment excluding exceptionals
(E/C) n/a 38%
---------------------------------------------------------- ---------- ---------
(i) Principal amounts drawn, excludes netting off of fees (see
note 18)
28. Subsidiaries
At 31 December 2020, EnQuest PLC had investments in the
following subsidiaries:
Proportion
of
nominal
value
of issued
shares
Country controlled
of by
Name of company Principal activity incorporation the Group
--------------------------------- --------------------------------------- --------------- -----------
Intermediate holding company and
provision of Group manpower and
EnQuest Britain Limited contracting/procurement services England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Heather Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Thistle Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Stratic UK (Holdings) Limited(i) Intermediate holding company England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Grove Energy Limited(1) Intermediate holding company Canada 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest ENS Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest UKCS Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Norge AS(i)2 of hydrocarbons Norway 100%
---------------------------------- ---------------------------------------- ------------- -----------
EnQuest Heather Leasing
Limited(i) Leasing England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EQ Petroleum Sabah Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
EnQuest Dons Leasing Limited(i) Dormant England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Energy Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Production Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
EnQuest Global Limited Intermediate holding company England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest NWO Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
EQ Petroleum Production Exploration, extraction and production
Malaysia Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Construction, ownership and operation
NSIP (GKA) Limited(3) of an oil pipeline Scotland 100%
---------------------------------- ---------------------------------------- ------------- -----------
Provision of Group manpower and
EnQuest Global Services contracting/procurement services
Limited(i)4 for the international business Jersey 100%
---------------------------------- ---------------------------------------- ------------- -----------
EnQuest Marketing and Trading
Limited Marketing and trading of crude oil England 100%
---------------------------------- ---------------------------------------- ------------- -----------
NorthWestOctober Limited(i) Dormant England 100%
---------------------------------- ---------------------------------------- ------------- -----------
EnQuest UK Limited(i) Dormant England 100%
---------------------------------- ---------------------------------------- ------------- -----------
EnQuest Petroleum Developments Exploration, extraction and production
Malaysia SDN. BHD(i)5 of hydrocarbons Malaysia 100%
---------------------------------- ---------------------------------------- ------------- -----------
EnQuest NNS Holdings Limited(i) Intermediate holding company England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest NNS Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
EnQuest Advance Holdings
Limited(i) Intermediate holding company England 100%
---------------------------------- ---------------------------------------- -------------
Exploration, extraction and production
EnQuest Advance Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- -------------
EnQuest Forward Holdings
Limited(i) Intermediate holding company England 100%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Forward Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
(i) Held by subsidiary undertaking
The Group has three branches outside the UK (all held by
subsidiary undertakings): EnQuest Global Services Limited (Dubai);
EnQuest Petroleum Production Malaysia Limited (Malaysia); and EQ
Petroleum Sabah Limited (Malaysia).
Registered office addresses:
1 Suite 2200, 1055 West Hastings Street, Vancouver, British Columbia, V6E 2E9
2 Fabrikkveien 9, Stavanger, 4033, Norway
3 Annan House, Palmerston Road, Aberdeen, Scotland, AB11 5QP, United Kingdom
4 Ground Floor, Colomberie House, St Helier, JE4 0RX, Jersey
5 c/o TMF, 10th Floor, Menara Hap Seng, No. 1 & 3, Jalan P. Ramlee 50250 Kuala Lumpur, Malaysia
29. Cash flow information
Cash generated from operations
Year ended Year ended
31 December 31 December
2020 2019
Notes $'000 $'000
---------------------------------------------------------- ----- ------------ ------------
Profit/(loss) before tax (565,975) (729,113)
---------------------------------------------------------- ----- ------------ ------------
Depreciation 5(c) 7,616 8,207
---------------------------------------------------------- ----- ------------ ------------
Depletion 5(b) 438,247 525,145
---------------------------------------------------------- ----- ------------ ------------
Exploration costs impaired and written off 4 - 150
---------------------------------------------------------- ----- ------------ ------------
Net impairment charge to oil and gas assets 4 422,495 812,448
---------------------------------------------------------- ----- ------------ ------------
Write down of inventory 24,940 14,588
---------------------------------------------------------- ----- ------------ ------------
Write down of asset 4 - 415
---------------------------------------------------------- ----- ------------ ------------
Change in fair value of investments 4 20
---------------------------------------------------------- ----- ------------ ------------
Share-based payment charge 5(f) 3,401 5,888
---------------------------------------------------------- ----- ------------ ------------
Gain on termination of Tanjong Baram risk service
contract 5(d) (10,209) -
---------------------------------------------------------- ----- ------------ ------------
Loss on derecognition of assets related to the Seligi
riser detachment 5(e) 956 -
---------------------------------------------------------- ----- ------------ ------------
Change in contingent consideration 22 (60,991) 72,685
---------------------------------------------------------- ----- ------------ ------------
Change in provisions 23 119,642 29,711
---------------------------------------------------------- ----- ------------ ------------
Amortisation of option premiums 19 (6,226) (4,936)
---------------------------------------------------------- ----- ------------ ------------
Unrealised (gain)/loss on commodity financial instruments 5(a) (8,778) 65,375
---------------------------------------------------------- ----- ------------ ------------
Unrealised (gain)/loss on other financial instruments 5(b) 1,932 378
---------------------------------------------------------- ----- ------------ ------------
Unrealised exchange loss/(gain) 5,067 15,587
---------------------------------------------------------- ----- ------------ ------------
Net finance expense 163,339 190,099
---------------------------------------------------------- ----- ------------ ------------
Operating profit before working capital changes 535,460 1,006,647
---------------------------------------------------------- ----- ------------ ------------
Decrease/(increase) in trade and other receivables 185,225 (78,056)
---------------------------------------------------------- ----- ------------ ------------
(Increase)/decrease in inventories (5,438) 6,423
---------------------------------------------------------- ----- ------------ ------------
(Decrease)/increase in trade and other payables (147,417) 59,604
---------------------------------------------------------- ----- ------------ ------------
Cash generated from operations 567,830 994,618
---------------------------------------------------------- ----- ------------ ------------
Changes in liabilities arising from financing activities
Loans and
borrowings Bonds Lease liabilities
(see note (see note (see note
18) 18) 24) Total
$'000 $'000 $'000 $'000
----------------------------------- ----------- ----------- ----------------- -----------
At 1 January 2019 (1,049,999) (990,281) (769,477) (2,809,757)
----------------------------------- ----------- ----------- ----------------- -----------
Cash movements:
----------------------------------- ----------- ----------- ----------------- -----------
Repayments of loans and borrowings 394,025 - - 394,025
----------------------------------- ----------- ----------- ----------------- -----------
Repayment of lease liabilities - - 135,125 135,125
----------------------------------- ----------- ----------- ----------------- -----------
Cash interest paid in year 64,370 67,485 - 131,855
----------------------------------- ----------- ----------- ----------------- -----------
Non-cash movements:
----------------------------------- ----------- ----------- ----------------- -----------
Additions - - (24,587) (24,587)
----------------------------------- ----------- ----------- ----------------- -----------
Interest/finance charge payable (67,749) (62,694) (55,686) (186,129)
----------------------------------- ----------- ----------- ----------------- -----------
Fee amortisation (811) (2,591) - (3,402)
----------------------------------- ----------- ----------- ----------------- -----------
Foreign exchange adjustments (1,049) (6,879) (1,541) (9,469)
----------------------------------- ----------- ----------- ----------------- -----------
Other non-cash movements (69) (1,023) - (1,092)
----------------------------------- ----------- ----------- ----------------- -----------
At 31 December 2019 (661,282) (995,983) (716,166) (2,373,431)
----------------------------------- ----------- ----------- ----------------- -----------
Cash movements:
----------------------------------- ----------- ----------- ----------------- -----------
Repayments of loans and borrowings 210,671 - - 210,671
----------------------------------- ----------- ----------- ----------------- -----------
Repayment of lease liabilities - - 123,001 123,001
----------------------------------- ----------- ----------- ----------------- -----------
Cash interest paid in year 31,056 - - 31,056
----------------------------------- ----------- ----------- ----------------- -----------
Non-cash movements:
----------------------------------- ----------- ----------- ----------------- -----------
Additions - - (2,812) (2,812)
----------------------------------- ----------- ----------- ----------------- -----------
Interest/finance charge payable (32,791) (73,476) (50,851) (157,118)
----------------------------------- ----------- ----------- ----------------- -----------
Fee amortisation (849) (2,261) - (3,110)
----------------------------------- ----------- ----------- ----------------- -----------
Foreign exchange adjustments (77) (7,923) (1,744) (9,744)
----------------------------------- ----------- ----------- ----------------- -----------
Disposal - - 726 726
----------------------------------- ----------- ----------- ----------------- -----------
Other non-cash movements 498 (49) - 449
----------------------------------- ----------- ----------- ----------------- -----------
At 31 December 2020 (452,774) (1,079,692) (647,846) (2,180,312)
----------------------------------- ----------- ----------- ----------------- -----------
Reconciliation of carrying value
Loans and
borrowings Bonds Lease liabilities
(see note (see note (see note
18) 18) 24) Total
$'000 $'000 $'000 $'000
--------------------------- ----------- ----------- ----------------- -----------
Principal (454,209) (1,048,355) (647,846) (2,150,410)
--------------------------- ----------- ----------- ----------------- -----------
Unamortised fees 1,925 3,314 - 5,239
--------------------------- ----------- ----------- ----------------- -----------
Accrued interest (note 17) (490) (34,651) - (35,141)
--------------------------- ----------- ----------- ----------------- -----------
At 31 December 2020 (452,774) (1,079,692) (647,846) (2,180,312)
--------------------------- ----------- ----------- ----------------- -----------
30. Subsequent events
Bressay transaction
The Group completed the Bressay transaction on 21 January 2021.
Under the agreement, EnQuest has assumed operatorship of the
licenses with a participating interest of 40.81% for an initial
consideration of GBP2.2 million, payable as a carry against 50% of
Equinor's net share of costs from the point EnQuest assumed
operatorship. EnQuest will also make a contingent payment of $15
million following OGA approval of a Bressay field development plan.
The contingent payment increases to $30 million in the event that
EnQuest sole risks Equinor in the submission of the field
development plan. There are no gross assets or profit before tax
associated with the assets.
Golden Eagle area transaction and Group refinancing
The Group signed an agreement with Suncor on 4 February to
purchase Suncor's entire 26.69% non-operated equity interest in the
Golden Eagle area, comprising the producing Golden Eagle, Peregrine
and Solitaire fields ('the Transaction').
The initial consideration is $325 million (which is subject to
working capital and other adjustments), with additional contingent
consideration of up to $50 million. The contingent consideration is
payable in the second half of 2023, if between July 2021 and June
2023 the Dated Brent average crude price equals or exceeds $55/bbl,
upon which $25 million is payable, or if the Dated Brent average
crude price equals or exceeds $65/bbl, upon which $50 million is
payable. A deposit of c.$3 million (being part of the initial
consideration) has been provided in 2021 by EnQuest and will be
forfeited in most circumstances if the Transaction does not
complete.
EnQuest plans to finance the Transaction through a combination
of a new secured debt facility, interim period post-tax cash flows
between the economic effective date of 1 January 2021 and
completion, and an equity raise (collectively the 'funding
arrangements').
It is anticipated the new secured debt facility, in respect of
which the Group is currently working closely with its leading
lending banks BNP and DNB, will incorporate the refinancing of the
existing outstanding senior credit facility. Further, the Group
anticipates raising up to $50 million of equity through a placing
and open offer, in which shareholders related to Amjad Bseisu are
expected to participate in line with their equity holdings. Amjad
Bseisu and/or persons related to him are expected to make financing
commitments assuring there will be no funding shortfall in respect
of this $50 million. These financing commitments constitute a
related party transaction and will therefore require independent
shareholder approval. J.P. Morgan Securities plc (which conducts
its UK investment banking activities as J.P. Morgan Cazenove) is
acting as global coordinator, bookrunner and sponsor to EnQuest in
connection with the placing and open offer, as financial adviser
and sponsor to EnQuest in connection with the Transaction and as
sponsor to EnQuest in connection with the related party
transaction.
Glossary - Non-GAAP measures
The Group uses Alternative Performance Measures ('APMs') when
assessing and discussing the Group's financial performance, balance
sheet and cash flows that are not defined or specified under IFRS.
The Group uses these APMs, which are not considered to be a
substitute for or superior to IFRS measures, to provide
stakeholders with additional useful information by adjusting for
exceptional items and certain remeasurements which impact upon IFRS
measures or, by defining new measures, to aid the understanding of
the Group's financial performance, balance sheet and cash
flows.
2020 2019
Business performance net profit attributable to EnQuest PLC
shareholders $'000 $'000
------------------------------------------------------------- --------- ---------
Reported net profit/(loss) (A) (625,802) (449,301)
------------------------------------------------------------- --------- ---------
Adjustments - remeasurements and exceptional items (note
4):
------------------------------------------------------------- --------- ---------
Unrealised (losses)/gains on oil derivative contracts (note
19) 8,778 (65,375)
------------------------------------------------------------- --------- ---------
Unrealised (gains)/losses on foreign exchange derivative
contracts (note 19) (1,932) 1,684
------------------------------------------------------------- --------- ---------
Unrealised (gains)/losses on carbon derivative contracts
(note 19) - (2,062)
------------------------------------------------------------- --------- ---------
Net impairment (charge)/reversal to oil and gas assets (note
10, 11 and note 12) (422,495) (812,448)
------------------------------------------------------------- --------- ---------
Unwind of contingent consideration (note 22) (77,259) (57,165)
------------------------------------------------------------- --------- ---------
Change in contingent consideration (note 22) 138,249 (15,520)
------------------------------------------------------------- --------- ---------
Redundancy provision (note 23) (5,792) -
------------------------------------------------------------- --------- ---------
PM8/Seligi riser provision (note 23) (5,902) -
------------------------------------------------------------- --------- ---------
Loss on decrecognition of assets related to the Seligi riser
detachment (note 5(e)) (956) -
------------------------------------------------------------- --------- ---------
KUFPEC provision - (15,630)
------------------------------------------------------------- --------- ---------
Other exceptional items - (585)
------------------------------------------------------------- --------- ---------
Pre-tax remeasurements and exceptional items (B) (367,309) (967,101)
------------------------------------------------------------- --------- ---------
Tax on remeasurements and exceptional items (C) (232,306) 303,460
------------------------------------------------------------- --------- ---------
Post-tax remeasurements and exceptional items (D = B + C) (599,615) (663,641)
------------------------------------------------------------- --------- ---------
Business performance net profit attributable to EnQuest PLC
shareholders (A - D) (26,187) 214,340
------------------------------------------------------------- --------- ---------
2020 2019
EBITDA $'000 $'000
-------------------------------------------------------------- --------- ---------
Reported profit/(loss) from operations before tax and finance
income/(costs) (310,069) (467,768)
-------------------------------------------------------------- --------- ---------
Adjustments:
-------------------------------------------------------------- --------- ---------
Remeasurements and exceptional items (note 4) 290,050 909,936
-------------------------------------------------------------- --------- ---------
Depletion and depreciation (note 5(b) and note 5(c)) 445,863 533,352
-------------------------------------------------------------- --------- ---------
Inventory revaluation 24,940 14,588
-------------------------------------------------------------- --------- ---------
Change in provision (note 23) 95,197 -
-------------------------------------------------------------- --------- ---------
Net foreign exchange (gain)/loss (note 5(d) and note 5(e)) 4,625 16,427
-------------------------------------------------------------- --------- ---------
Business performance EBITDA (E) 550,606 1,006,535
-------------------------------------------------------------- --------- ---------
EBITDA is calculated on a 'Business performance' basis, and is
calculated by taking profit/(loss) from operations before tax and
finance income/(costs) and adding back depletion, depreciation,
foreign exchange movements, inventory revaluation, change in
provision and the realised gain/(loss) on foreign currency and
derivatives related to capital expenditure.
2020 2019
Total cash and available facilities $'000 $'000
---------------------------------------------- --------- ---------
Available cash 113,185 144,214
---------------------------------------------- --------- ---------
Ring-fenced cash 107,970 73,985
---------------------------------------------- --------- ---------
Restricted cash 1,675 2,257
---------------------------------------------- --------- ---------
Total cash and cash equivalents (F) (note 14) 222,830 220,456
---------------------------------------------- --------- ---------
Available credit facilities 450,000 535,000
---------------------------------------------- --------- ---------
Credit facility - Drawn down (appendix) (360,000) (460,000)
---------------------------------------------- --------- ---------
Letter of credit (note 18) (28,778) (6,849)
---------------------------------------------- --------- ---------
Available undrawn facility (G) 61,222 68,151
---------------------------------------------- --------- ---------
Total cash and available facilities (F + G) 284,052 288,607
---------------------------------------------- --------- ---------
2020 2019
Net debt $'000 $'000
---------------------------------------------- ---------- ---------
Borrowings (note 18):
---------------------------------------------- ---------- ---------
Credit facility - Drawn down 360,000 460,000
---------------------------------------------- ---------- ---------
Credit facility - PIK 17,270 15,097
---------------------------------------------- ---------- ---------
Sculptor Capital facility 65,776 120,287
---------------------------------------------- ---------- ---------
SVT working capital facility 9,238 31,899
---------------------------------------------- ---------- ---------
Tanjong Baram project financing facility - 31,730
---------------------------------------------- ---------- ---------
Borrowings (H) 452,284 659,013
---------------------------------------------- ---------- ---------
Bonds (note 18):
---------------------------------------------- ---------- ---------
High yield bond 796,528 741,573
---------------------------------------------- ---------- ---------
Retail bond 248,513 224,658
---------------------------------------------- ---------- ---------
Bonds (I) 1,045,041 966,231
---------------------------------------------- ---------- ---------
Non-cash accounting adjustments (note 18):
---------------------------------------------- ---------- ---------
Unamortised fees on loans and borrowings 1,925 2,625
---------------------------------------------- ---------- ---------
Unamortised fees on bonds 3,314 5,572
---------------------------------------------- ---------- ---------
Non-cash accounting adjustments (J) 5,239 8,197
---------------------------------------------- ---------- ---------
Debt (H + I + J) (K) 1,502,564 1,633,441
---------------------------------------------- ---------- ---------
Less: Cash and cash equivalents (note 14) (E) 222,830 220,456
---------------------------------------------- ---------- ---------
Net debt/(cash) (K - F) (L) 1,279,734 1,412,985
---------------------------------------------- ---------- ---------
2020 2019
Net debt/EBITDA $'000 $'000
-------------------------------- ---------- ---------
Net debt (L) 1,279,734 1,412,985
-------------------------------- ---------- ---------
Business performance EBITDA (E) 550,606 1,006,535
-------------------------------- ---------- ---------
Net debt/EBITDA (L/E) 2.3 1.4
-------------------------------- ---------- ---------
2020 2019
Cash capex $'000 $'000
--------------------------------------------------------------- --------- ---------
Reported net cash flows (used in)/from investing activities (120,597) (257,838)
--------------------------------------------------------------- --------- ---------
Adjustments:
--------------------------------------------------------------- --------- ---------
Repayment of Magnus contingent consideration - Profit share 41,071 21,581
--------------------------------------------------------------- --------- ---------
Net cash received on termination of Tanjong Baram risk service
contract (51,054) -
--------------------------------------------------------------- --------- ---------
Interest received (796) (1,225)
--------------------------------------------------------------- --------- ---------
Cash capex (131,376) (237,482)
--------------------------------------------------------------- --------- ---------
2020 2019
Free cash flow $'000 $'000
--------------------------------------------------- --------- ---------
Net cash flows from/(used in) operating activities 522,085 962,271
--------------------------------------------------- --------- ---------
Net cash flows from/(used in) investing activities (120,597) (257,838)
--------------------------------------------------- --------- ---------
Net cash flows from/(used in) financing activities (401,014) (729,996)
--------------------------------------------------- --------- ---------
Adjustments:
--------------------------------------------------- --------- ---------
Repayment of loans and borrowings 210,671 394,025
--------------------------------------------------- --------- ---------
Free cash flow 211,145 368,462
--------------------------------------------------- --------- ---------
2020 2019
Revenue sales $'000 $'000
---------------------------------------------------------- -------- ---------
Revenue from crude oil sales (note 5(a)) (M) 779,865 1,548,177
---------------------------------------------------------- -------- ---------
Revenue from gas and condensate sales (note 5(a)) (N) 60,486 120,242
---------------------------------------------------------- -------- ---------
Realised (losses)/gains on oil derivative contracts (note
5(a)) (P) (6,059) 24,756
---------------------------------------------------------- -------- ---------
2020 2019
Barrels equivalent sales kboe kboe
------------------------------- ------- ------
Sales of crude oil (Q) 18,758 24,098
------------------------------- ------- ------
Sales of gas and condensate(i) 3,471 4,082
------------------------------- ------- ------
Total sales (R) 22,229 28,180
------------------------------- ------- ------
(i) Includes volumes related to onward sale of third-party gas
purchases not required for injection activities at Magnus
2020 2019
Average realised prices $/Boe $/Boe
-------------------------------------------------------------- ------ ------
Average realised oil price, excluding hedging (M/Q) 41.6 64.2
-------------------------------------------------------------- ------ ------
Average realised oil price, including hedging ((M + P)/Q) 41.3 65.3
-------------------------------------------------------------- ------ ------
Average realised blended price, excluding hedging ((M + N)/R) 37.8 59.2
-------------------------------------------------------------- ------ ------
Average realised blended price, including hedging ((M + N
+ P)/R) 37.5 60.1
-------------------------------------------------------------- ------ ------
2020 2019
Operating costs $'000 $'000
-------------------------------------------------------------- --------- ---------
Reported cost of sales (note 5(b)) 799,081 1,243,948
-------------------------------------------------------------- --------- ---------
Adjustments:
-------------------------------------------------------------- --------- ---------
Remeasurements and exceptional items (note 5(b)) (13,626) (378)
-------------------------------------------------------------- --------- ---------
Depletion of oil and gas assets (note 5(b)) (438,247) (525,145)
-------------------------------------------------------------- --------- ---------
(Credit)/charge relating to the Group's lifting position
and inventory (note 5(b)) 34,801 (102,853)
-------------------------------------------------------------- --------- ---------
Other cost of sales (note 5(b)) (53,367) (97,459)
-------------------------------------------------------------- --------- ---------
Operating costs 328,642 518,113
-------------------------------------------------------------- --------- ---------
Less realised (gain)/loss on derivative contracts (note 5(b)) 572 1,707
-------------------------------------------------------------- --------- ---------
Operating costs directly attributable to production 329,214 516,406
-------------------------------------------------------------- --------- ---------
Comprising of:
-------------------------------------------------------------- --------- ---------
Production costs (S) (note 5(b)) 265,529 441,624
-------------------------------------------------------------- --------- ---------
Tariff and transportation expenses (T) (note 5(b)) 63,685 74,782
-------------------------------------------------------------- --------- ---------
Operating costs directly attributable to production 329,214 516,406
-------------------------------------------------------------- --------- ---------
2020 2020
Barrels equivalent produced kboe kboe
-------------------------------------- ------ ------
Total produced (working interest) (U) 21,636 25,041
-------------------------------------- ------ ------
2020 2019
Unit opex $/Boe $/Boe
----------------------------------------- ------ ------
Production costs (S/U) 12.3 17.6
----------------------------------------- ------ ------
Tariff and transportation expenses (T/U) 2.9 3.0
----------------------------------------- ------ ------
Total unit opex ((S + T)/U) 15.2 20.6
----------------------------------------- ------ ------
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END
FR EELBLFXLZBBL
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March 25, 2021 03:00 ET (07:00 GMT)
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