TIDMENQ
RNS Number : 8360F
EnQuest PLC
24 March 2022
EnQuest PLC
Results for the year ended 31 December 2021 and 2022 outlook
24 March 2022
Unless otherwise stated, all figures are on a Business
performance basis and are in US Dollars.
Comparative figures for the Income Statement relate to the
period ended 31 December 2020 and the Balance Sheet as at 31
December 2020. Alternative performance measures are reconciled
within the 'Glossary - Non-GAAP measures' at the end of the
Financial Statements.
EnQuest Chief Executive, Amjad Bseisu, said:
"We made good progress against our strategic objectives in 2021,
concluding three acquisitions, refinancing our senior secured debt
facility, generating significant free cash flow of $396.8 million
and reducing our year end net debt to $1,222.0 million, its lowest
level since 2014. We have made strong progress on emissions
reduction, which continues to be a focus for the Group.
"We have also started 2022 well, with production to the end of
February averaging 50,408 Boepd, towards the top end of our full
year guidance range. We have also continued to reduce our net debt,
down to $1,090.0 million at the end of February, in line with our
strategic priorities. With a supportive oil price environment and
an active programme of nine wells and seven workovers in 2022, our
largest sanctioned programme since 2014 and our first new wells in
over two years, we remain confident on delivering a good
performance this year.
"The acquisition of Golden Eagle has strengthened our portfolio,
building on our track record of value creation through innovative,
disciplined M&A. The acquisitions of Bressay and Bentley have
added almost 250 MMboe of 2C resources, adding to those already in
place at Magnus, Kraken, PM8/Seligi and PM409, providing EnQuest
with longer-term potential development opportunities.
"We remain focused on continuing to reduce our net debt while
selectively investing in our low-cost, quick payback well portfolio
in order to sustain our production base.
"EnQuest's business is strongly positioned to play an important
role in the energy transition. We will do so by responsibly
optimising production, leveraging existing infrastructure,
delivering decommissioning and exploring new energy and
decarbonisation opportunities."
2021 performance
* Group net production averaged 44,415 Boepd(1) (2020: 59,116 Boepd)
* Revenue and other operating income of $1,320.3 million (2020: $855.1
million) and adjusted EBITDA of $742.9 million (2020: $550.6 million)
reflects materially higher oil prices, partially offset by lower
production
* Cash generated from operations was $756.9 million (2020: $567.2
million)
* Cash expenditures of $117.6 million (2020: $173.0 million); cash
capital expenditure of $51.8 million (2020: $131.4 million) and
cash abandonment expenditure of $65.8 million (2020: $41.6 million)
* Strong free cash flow generation(2) of $396.8 million (2020: $210.5
million)
* Cash and available facilities amounted to $318.7 million at 31 December
2021 (2020: $284.1 million), with net debt reduced to $1,222.0 million
(2020: $1,279.7 million)
* Statutory reported profit after tax was $377.0 million (2020 (restated):
loss after tax of $469.9 million)
(1) Includes Golden Eagle contribution for the period 22 October
to 31 December, averaged over the 12 months to the end of
December
(2) Net change in cash and cash equivalents less net
(repayments)/proceeds from loan facilities, acquisition costs
($258.6 million), the accelerated repayment of the BP vendor loan
($58.7 million) and net proceeds from the firm placing, placing and
open offer ($47.2 million)
Significant business development
* Successfully completed the acquisition of a 26.69% non-operated
interest in the producing Golden Eagle area in October, for an initial
consideration of $325.0 million; a highly cash generative asset
providing significant value enhancement through the addition of
c.18 MMbbls to year end 2021 net 2P reserves and c.3 MMbbls to net
2C resources
* Completed purchase of 40.81% equity interest in the Bressay heavy-oil
field for an initial consideration of GBP2.2 million, adding c.115
MMbbls of net 2C resources
* Completed purchase of 100.0% equity interest in the P1078 licence
containing the proven Bentley heavy-oil discovery, adding c.131
MMbbls of 2C resources
Board changes
* Jonathan Swinney has notified the Board of his intention to step
down from the Board as Chief Financial Officer and Executive Director
at a date to be determined in due course (see separate announcement)
2022 performance and outlook
* Year to date February production averaged 50,408 Boepd, in line
with full year guidance
* Net debt amounted to $1,090.0 million at 28 February
* Hedges in place for c.8.6 MMbbls of oil with an average floor price
of c.$63/bbl and an average ceiling price of c.$78/bbl
* Full year average net Group production expected to be between 44,000
and 51,000 Boepd
* Full year operating costs of c.$430 million
* Cash capital expenditure of c.$165 million, with cash abandonment
expenditure of c.$75 million
Production and financial information
Business performance measures 2021 2020 Change
%
Production (Boepd) 44,415 59,116 (24.9)
----------------------------------------- ---------- ---------- -------
Revenue and other operating income
($m)(1,2) 1,320.3 855.1 54.4
----------------------------------------- ---------- ---------- -------
Realised oil price ($/bbl)(1,3) 68.6 41.3 66.1
----------------------------------------- ---------- ---------- -------
Average unit operating costs ($/Boe)(3) 20.5 15.2 34.9
----------------------------------------- ---------- ---------- -------
Adjusted EBITDA ($m)(3) 742.9 550.6 34.9
----------------------------------------- ---------- ---------- -------
Cash expenditures ($m) 117.6 173.0 (32.0)
----------------------------------------- ---------- ---------- -------
Capital(3) 51.8 131.4 (60.6)
----------------------------------------- ---------- ---------- -------
Abandonment 65.8 41.6 58.2
----------------------------------------- ---------- ---------- -------
Free cash flow ($m)(2, 3) 396.8 210.5 88.5
----------------------------------------- ---------- ---------- -------
2021 2020
----------------------------------------- ---------- ---------- -------
Net (debt)/cash ($m)(3) (1,222.0) (1,279.7) (4.5)
----------------------------------------- ---------- ---------- -------
Statutory measures 2021 2020 Change
%
----------------------------------------- ---------- ---------- -------
Reported revenue and other operating
income ($m)(2,4) 1,265.8 863.9 46.5
----------------------------------------- ---------- ---------- -------
Reported gross profit ($m) 358.2 64.8 452.8
----------------------------------------- ---------- ---------- -------
Reported profit/(loss) after tax
($m)(2) 377.0 (469.9) -
----------------------------------------- ---------- ---------- -------
Reported basic earnings/(loss) per
share (cents)(2) 21.7 (29.0) -
----------------------------------------- ---------- ---------- -------
Cash generated from operations ($m)(2) 756.9 567.2 33.4
----------------------------------------- ---------- ---------- -------
Net increase/(decrease) in cash
and cash equivalents(2) ($m) 67.4 (0.2) -
----------------------------------------- ---------- ---------- -------
Notes:
(1) Including realised losses of $67.7 million (2020: realised
losses of $6.1 million) associated with EnQuest's oil price
hedges
(2) Comparative information for 2020 has been restated. See note
2 Basis of preparation - Restatements
(3) See reconciliation of alternative performance measures
within the 'Glossary - Non-GAAP measures' starting on page 66. Cash
capital expenditure includes $13.2 million associated with the
PM8/Seligi riser replacement
Note, EnQuest defines net debt as excluding finance lease
liabilities
(4) Including net realised and unrealised losses of $122.2
million (2020: net realised and unrealised gains of $2.7 million)
associated with EnQuest's oil price hedges
Production details
Average daily production 1 Jan 2021 to 1 Jan 2020
on a net working 31 Dec 2021 to
interest basis 31 Dec 2020
-------------------------- -------------- -------------
(Boepd) (Boepd)
UK Upstream
- Magnus 11,870 17,416
- Kraken 21,964 26,450
- Golden Eagle(1) 1,701 -
- Other Upstream
(2) 3,685 6,468
-------------- -------------
UK Upstream 39,220 50,334
UK Decommissioning
(3) 167 2,346
-------------- -------------
Total UK 39,387 52,680
Total Malaysia 5,028 6,436
-------------- -------------
Total EnQuest 44,415 59,116
-------------- -------------
(1) Golden Eagle contribution for the period 22 October to 31
December, averaged over the 12 months to the end of December
(2) Other Upstream: Scolty/Crathes, Greater Kittiwake Area and
Alba
(3) UK Decommissioning: the Dons, Alma/Galia
2021 performance summary
During the year, EnQuest strengthened its portfolio through the
Golden Eagle acquisition and, supported by an improving oil price
environment, generated material free cash flow enabling the Group
to simplify its balance sheet and further reduce net debt. The
Group also made good progress on its decommissioning programmes,
significantly reduced Scope 1 and 2 CO(2) equivalent emissions and
established an Infrastructure and New Energy business to explore
renewable energy and decarbonisation opportunities.
Production of 44,415 Boepd reflected a strong performance at
Kraken and the contribution from Golden Eagle following completion
of the acquisition, offset by topside and well integrity related
outages at Magnus, planned maintenance and a subsea power umbilical
failure at the Greater Kittiwake Area ('GKA') and expected natural
declines across the portfolio. The natural declines were to a large
extent a consequence of the necessary pause in the Group's drilling
programme following materially lower oil prices experienced in 2020
and into 2021.
Adjusted EBITDA, cash generated by operations and free cash flow
were $742.9 million, $756.9 million and $396.8 million,
respectively, with the material increase from 2020 primarily
reflecting higher market prices. Cash capital and abandonment
expenditures totalled $117.6 million Capital expenditure of $51.8
million primarily reflected the Magnus production enhancement
campaign and the PM8/Seligi riser replacement. Cash abandonment
expenditure of $65.8 million was focused on decommissioning
activities at Heather, Thistle and the Dons.
Liquidity and net debt
At 31 December 2021, net debt was $1,222.0 million, down $57.7
million from $1,279.7 million at 31 December 2020 with a net debt
to adjusted EBITDA ratio of 1.6x. Strong free cash flow generation
of $396.8 million enabled the payment of $249.7 million cash
consideration for the Golden Eagle acquisition and repayment of the
BP vendor loan and Sculptor Capital facility, simplifying the
Group's debt structure. During the year, EnQuest successfully
refinanced its senior credit facility ('RCF') into a new senior
secured debt facility ('RBL') of up to $750.0 m illion . The strong
free cash flow generation also resulted in a lower than expected
drawdown on the Group's RBL facility, and facilitated an early
voluntary repayment of $70.0 million prior to the year end. At the
end of December, the RBL facility was drawn to $415.0 million.
Total cash and available facilities were $318.7 million, including
restricted funds and ring-fenced funds held in joint venture
operational accounts totalling $191.4 million.
As at 28 February 2022, net debt was $1,090.0 million, down a
further $132.0 million from 31 December 2021, reflecting strong
free cash flow and positive working capital movements. As at the
date of this announcement, the Group had made further early
voluntary repayments of its RBL facility totalling $85.3 million,
with the amount drawn down reduced to $329.7 million. EnQuest is
targeting progress towards a net debt to adjusted EBITDA ratio of
0.5x.
Business development
In January 2021, the Group completed the acquisition of a 40.81%
equity interest in and operatorship of the Bressay oil field. This
acquisition provides a low-cost addition of 115 MMbbls (net) 2C
resources. The initial consideration was GBP2.2 million, payable as
a carry against 50% of Equinor's net share of costs from the point
EnQuest assumed operatorship.
In July 2021, the Group completed the acquisition of the 100.00%
equity interest in the P1078 licence containing the proven Bentley
heavy-oil discovery from Whalsay Energy Holdings Limited ('WEL').
This discovery, which has added 131 MMboe (net) 2C resources, is
within c.15 kilometres of the Group's existing Kraken and Bressay
operated interests, offering further long-term potential
development opportunities and other synergies. Upon completion,
EnQuest funded certain accrued costs and obligations of WEL, which
amounted to less than $2.0 million.
In October 2021, the Group completed the acquisition of a 26.69%
non-operated interest in the producing Golden Eagle area from
Suncor Energy UK, for an initial consideration of $325.0 million.
The transaction has added 18 MMboe to net 2P reserves.
Reserves and resources
Net 2P reserves at the end of 2020 were c.194 MMboe (2020: c.189
MMboe) and have been audited on a consistent basis with prior
years. During the year, the Group produced 8.2% of its year-end
2020 2P reserves base but this was more than offset by the
acquisition of Golden Eagle, which resulted in an addition of c.18
MMboe. Net 2C resources were c.402 MMboe (2020: c.164 MMboe), an
increase of 145.1% compared to the end of 2020 primarily as a
result of the acquisitions of equity interests in the Bressay field
and Bentley discovery, which combined added 246 MMboe.
Environmental, Social and Governance
The Group has made excellent progress in reducing its absolute
Scope 1 and 2 emissions during the year, with CO(2) equivalent
emissions reduced by 14.7%, reflecting operational improvements and
increased workforce awareness driving lower flaring, fuel gas and
diesel usage. Since 2018, UK Scope 1 and 2 emissions have reduced
by 43.5%, which is significantly ahead of the UK Government's North
Sea Transition Deal target of achieving a 10% reduction in Scope 1
and 2 CO(2) equivalent emissions by 2025 and close to the 50%
reduction targeted by 2030.
The health, safety and wellbeing of our employees is our top
priority. Despite the challenges and uncertainties of 2021, the
Group's Lost Time Incident ('LTI') performance remained relatively
stable with a Group LTI frequency(1) of 0.21 (2020: 0.22), slightly
better than the International Association of Oil and Gas Producers
benchmark of 0.22.
(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)
With respect to COVID-19, 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 changes in general infection rates and associated modifications
to processes and controls impacted the execution and cost of some
planned activities in 2021. In Malaysia, extended quarantine rules
led to significant changes to working rotas and additional costs
related to testing and standby rates, while several workscopes were
adversely affected by COVID-related impacts on the supply chain.
Magnus suffered a seven-day shutdown due to key control room
personnel being unavailable due to COVID. The Group is cognisant of
the ongoing risks presented by the evolving situation, but at the
time of this publication, day-to-day operations in 2022 have not
been materially affected.
In February 2021, the Board was pleased to appoint Liv Monica
Stubholt as a Non-Executive Director of the EnQuest Board. Liv
Monica also became a member of the Audit Committee and the Safety,
Climate and Risk Committee. Her appointment builds on the Board's
extensive experience in the energy industry and further strengthens
its governance position.
In January 2022, Rani Koya was appointed to the Board as a
Non-Executive Director and member of the Technical and Reserves
Committee. Rani has worked extensively in major energy companies in
a variety of technical, project management and executive management
roles across the globe. She is currently the CEO of a renewable
energy company.
Jonathan Swinney has notified the Board of his intention to step
down from the Board as Chief Financial Officer ('CFO') and
Executive Director at a date to be determined in due course. Salman
Malik, currently Managing Director - Corporate Development,
Infrastructure and New Energy and a member of the Group's Executive
Committee, will succeed Jonathan as CFO and as an Executive
Director upon Jonathan's departure.
Philip Holland, currently Chairman of the Safety, Climate and
Risk Committee, will be stepping down as a Director at the
Company's 2022 Annual General Meeting. Liv Monica Stubholt will
replace Philip as Chair of the Committee in May 2022.
2022 performance and outlook
Group net production averaged 50,408 Boepd for the year to date
February. For the full year, the Group's net production is expected
to be between 44,000 and 51,000 Boepd. The infill drilling and
workover campaigns at Magnus, Golden Eagle and PM8/Seligi are
expected largely to mitigate natural declines at these fields. At
PM8/Seligi, the outlook is positive with the acceleration of
securing a dive support vessel resulting in the riser being
connected ahead of schedule and all the wells now onstream.
Extensive maintenance shutdowns are also planned at both Magnus and
Kraken. Kraken gross production is expected to be between 22,000
Boepd and 26,000 Boepd (15,500 Boepd to 18,500 Boepd net),
reflecting the planned shutdown and natural decline.
At current foreign exchange rates and oil prices, operating
costs are expected to be approximately $430 million. The increase
versus 2021 includes a full year of Golden Eagle operating costs,
planned well workover activities in Malaysia, an enhanced
maintenance programme on Magnus and significantly increased
emissions and diesel costs as a result of higher market prices.
Cash capital expenditure is expected to be around $165 million,
primarily relating to drilling campaigns at Magnus (three wells),
Golden Eagle (two wells) and in Malaysia (four wells), as well as
preparatory activities ahead of future drilling at Kraken.
Abandonment expense is expected to total approximately $75 million,
primarily reflecting well P&A decommissioning programmes at the
Heather/Broom and Thistle/Deveron fields.
EnQuest has hedged a total of 8.6 MMbbls for 2022 primarily
using costless collars, with an average floor price of c.$63/bbl
and an average ceiling price of c.$78/bbl. For 2023, the Group has
hedged a total of 3.5 MMbbls with an average floor price of
c.$57/bbl and an average ceiling of c.$77/bbl.
The Group continues to explore options to refinance its Retail
and High Yield Bonds ahead of maturity in October 2023.
Summary financial review of 2021
(all figures quoted are in US Dollars and relate to Business
performance unless otherwise stated)
The Group made good progress on its strategic aims during 2021.
Supported by higher oil prices and capital discipline, EnQuest
generated strong free cash flow of $396.8 million, up 88.5%
compared to 2020, which, along with the signing of a new senior
secured credit facility ('RBL'), enabled the Group to simplify its
capital structure, facilitate the Golden Eagle acquisition and
reduce overall net debt.
Revenue for 2021 was $1,320.3 million, 54.4% higher than in 2020
($855.1 million) reflecting the materially higher realised prices
partially offset by lower volumes. Revenue is predominantly derived
from crude oil sales, which totalled $1,139.2 million, 46.1% higher
than in 2020 ($779.9 million), reflecting the significantly higher
oil prices, offset by lower production. Revenue from the sale of
condensate and gas, primarily in relation to the onward sale of
third-party gas purchases not required for injection activities at
Magnus, was $244.1 million (2020: $60.5 million), as a result of
the significantly higher gas prices.
The Group's commodity hedge programme resulted in realised
losses of $67.7 million in 2021 (2020: losses of $6.1 million). The
Group's average realised oil price excluding the impact of hedging
was $73.0/bbl, 75.5% higher than in 2020 ($41.6/bbl). The Group's
average realised oil price including the impact of hedging was
$68.6/bbl in 2021, 66.4% higher than 2020 ($41.3/bbl).
Total cost of sales were $900.4 million for the year ended 31
December 2021, 14.6% higher than in 2020 ($785.5 million).
The Group's operating costs decreased by $7.6 million to $321.0
million (2020: $328.6 million), primarily reflecting reduced tariff
and transportation costs due to lower production and realised
derivative gains related to emissions allowances. This was largely
offset by higher production costs driven by materially higher
emission allowances costs, lower lease charter credits reflecting
higher uptime at Kraken driven by the continued strong performance
of the FPSO and remediation costs at Magnus. Unit operating costs
(excluding hedging) increased by 34.9% to $20.5/Boe (2020:
$15.2/Boe), reflecting lower production. Unit operating costs
including hedging were $19.8/Boe (2020: $15.2/Boe).
Total cost of sales also included non-cash depletion expense of
$305.6 million, 30.3% lower than in 2020 ($438.2 million), mainly
reflecting lower production.
The charge relating to the Group's lifting position and
inventory was $62.3 million (2020: credit of $34.8 million). This
reflects a switch to an $18.0 million net overlift position at 31
December 2021 from a $3.0 million net underlift position at 31
December 2020. The charge for the year is also impacted by the
post-acquisition revaluation of the Golden Eagle underlift
position.
Other cost of operations of $211.5 million were materially
higher than in 2020 ($53.5 million), principally as a result of
higher Magnus-related third-party gas purchases following the
increase in associated market prices, offset by a partial release
of the inventory provision.
Adjusted EBITDA for 2021 was $742.9 million, up 34.9% compared
to 2020 ($550.6 million), primarily as a result of higher
revenue.
The tax charge for 2021 of $53.7 million (2020: $172.5 million
tax credit), excluding remeasurements and exceptional items, is
mainly due to the taxable profits generated in the year exceeding
the Ring Fence Expenditure Supplement ('RFES') on UK activities
generated in the year. UK North Sea corporate tax losses at the end
of the year decreased to $3,011.0 million (2020: $3,183.9
million).
Remeasurements and exceptional items resulting in a post-tax net
gain of $156.7 million have been disclosed separately for the year
ended 31 December 2021 (2020: loss of $443.8 million). Revenue
included unrealised losses of $54.5 million in respect of the
mark-to-market movement on the Group's commodity contracts (2020:
unrealised gains of $8.8 million). Other income included a $140.1
million gain in relation to the fair value recalculation of the
Magnus contingent consideration reflecting a forecast reduction in
Magnus future cash flows (2020: $138.2 million gain). Other finance
costs mainly relate to the unwinding of contingent consideration
from the acquisition of Magnus and associated infrastructure and
interest charged on the vendor loan of $58.4 million (2020: $77.3
million).
The Group's reported cash generated from operations for 2021 was
$756.9 million (2020: $567.2 million), primarily as a result of
higher revenue. Free cash flow for 2021 was $396.8 million (2020:
$210.5million).
Net debt decreased by $57.7 million to $1,222.0 million at 31
December 2021 (31 December 2020: $1,279.7 million). This includes
$225.0 million of payment in kind ('PIK') interest that has been
capitalised to the principal of the facilities pursuant to the
terms of the Group's November 2016 refinancing (31 December 2020:
$205.8 million).
In June, the Group announced that it had signed a new RBL of
$600.0 million with an additional amount of $150.0 million for
letters of credit for up to seven years, subject to the timing of
the refinancing of the bonds. Also in June, the Group repaid the
outstanding principal and interest on the Sculptor Capital facility
from free cash flow.
In July 2021, $360.0 million was drawn down from the Group's new
RBL facility. The proceeds were used to repay the entire
outstanding balance on the RCF, which at the time of repayment was
$354.5 million, including PIK and accrued interest. Also in July,
$58.7 million, representing the full amount of the outstanding
principal and interest on the Magnus vendor loan, was repaid and
the Group successfully completed an equity raise consisting of net
proceeds of $47.2 million.
In October 2021 and following shareholder approval of the Golden
Eagle acquisition, a further $125.0 million was drawn down against
the RBL to partially fund the $249.7 million cash consideration
with the acquisition completing on 22 October 2021. In December
2021, EnQuest made a voluntary early repayment of $70.0 million on
the RBL and with further early voluntary repayments totalling $85.3
million made in the first quarter of 2022.
- 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 Investor Relations, Communications
& Reporting)
Craig Baxter (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 09.30
today - London time. The presentation will be accessible via a
webcast by clicking here . A conference call facility will also be
available at 09.30 on the following numbers:
Conference call details:
UK : +44 (0) 800 279 6619
International: +44 (0) 207 192 8338
Confirmation Code: 3308419
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
We continued to make good progress against our strategic
objectives of deliver, de-lever and grow. The acquisition of the
Golden Eagle asset has further strengthened our portfolio, while
the low-cost acquisitions of material resources at Bressay and
Bentley provide us with future near-field development opportunities
that can utilise our heavy oil expertise and differential
capability in subsea drilling and tie-backs. Production in the year
was primarily impacted by a combination of well and topside
integrity-related outages at Magnus and natural declines across the
portfolio. At Kraken, the floating production, storage and
offloading vessel continued to perform well and production at
PM8/Seligi was in line with expectations. We demonstrated our
decommissioning project capability with significant levels of
activity throughout 2021 and have established an Infrastructure and
New Energy business with overall responsibility for advancing
renewable energy and decarbonisation opportunities. During 2021,
the Group also made excellent progress in reducing its absolute
Scope 1 and 2 emissions, with CO2 equivalent emissions reduced by
14.7%. Since 2018, UK Scope 1 and 2 emissions have been reduced by
43.5%, which is significantly ahead of the UK Government's
near-term North Sea Transition Deal targets.
As always, the safety of EnQuest's people and assets remained an
absolute priority. I was particularly pleased to see the Group's
Lost Time Incident ('LTI') performance remained 'top quartile' with
a Group LTI frequency1 of 0.21.
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)
We also continued to evolve our approach to managing COVID-19 to
keep our people safe. However, we received a number of improvement
notices from the UK Health & Safety Executive ('HSE') relating
to our Magnus and SVT operations. We continue to improve further
our process safety arrangements and all notices have been or will
be fully complied with in accordance with the agreed activity set
and timetable.
2021 also saw strong demand for oil which, when combined with
supply-side constraints, led to oil prices recovering strongly. The
Group's average realised oil price in 2021, including the impact of
its commodity hedge programme, was $68.6/bbl, up 66.4% from
$41.3/bbl in 2020. This improved commodity price environment
enabled the Group to generate strong free cash flow of $396.8
million, an increase of $186.3 million from 2020, and lower net
debt to $1,222.0 million, its lowest level since 2014.
Operational performance
EnQuest's average production decreased by 24.9% to 44,415 Boepd,
primarily driven by topside and well integrity related outages at
Magnus and expected natural declines across the portfolio,
partially offset by the contribution from Golden Eagle following
completion of the acquisition on 22 October 2021. The natural
declines were to a large extent a consequence of the necessary
pause in the Group's drilling programme following materially lower
oil prices experienced in 2020 and into 2021.
Kraken continued to perform well, delivering top quartile
production efficiency of 88% and gross production in line with
guidance. During the fourth quarter of 2021, the asset reached the
milestone of more than 50 MMbbls (gross) produced since first oil;
a great achievement by the combined EnQuest and Bumi Armada team.
The 3D seismic gathered during the summer will allow the Group to
evaluate fully the development potential of the western area of the
field in addition to supporting ongoing optimisation of the main
Kraken field, including potential infill opportunities. At
PM8/Seligi, initial production recovery activities were
accelerated, offsetting the delayed riser replacement, while at the
Greater Kittiwake Area the power umbilical supporting the Mallard
and Gadwall wells was successfully replaced in September, restoring
both wells to production. However, production at Magnus was
disappointing. Performance was impacted by well integrity and
topside issues, an unplanned third-party outage and natural
decline. During the year, a production enhancement programme was
undertaken, restoring four wells to production, although a
compressor gearbox failure in September resulted in single
compression train operations for much of the fourth quarter.
During the year, we produced 8.2% of our year-end 2020 2P
reserves base. However, with the acquisition of Golden Eagle adding
c.18 MMboe at the end of 2021, the Group's 2P reserves at the end
the year were around 194 MMboe, marginally higher than the c.189
MMboe at the end of 2020. Following the acquisitions of interests
in the Bressay field and the Bentley discovery in the UK, 2C
resources increased by 145.1% from the end of 2020 to around 402
MMboe, with both fields each adding more than 100 MMboe of net 2C
resources. Other material 2C resources are located at Magnus and
Kraken in the UK and PM8/Seligi and PM409, offshore Malaysia.
Following our decisions in 2020 to permanently cease production
at several of our highest cost assets, 2021 saw an associated
increase in decommissioning activity enabling the Group to
demonstrate its decommissioning project capability. Activities were
focused on well abandonments at Heather, platform re-habitation and
other preparatory activities ahead of the planned well abandonment
programme at Thistle, and cessation of production at the Dons
field, including the removal of the Northern Producer Floating
Production Facility.
In August, the Group established an Infrastructure and New
Energy business to support the ongoing transformation of SVT and
EnQuest's energy transition ambitions. The new business will focus
on strengthening and extending the life of operations and assessing
and delivering new energy opportunities over the medium to long
term to create a hub of growth in infrastructure and renewables at
SVT. Constructive initial engagement with a variety of
stakeholders, including potential technical and financial partners,
is ongoing.
Financial performance
The Group's adjusted EBITDA and statutory gross profit increased
by 34.9% to $742.9 million and 453.0% to $358.2 million,
respectively, reflecting the material increase in realised oil
prices partially offset by lower production. Operating costs for
the year of $321.0 million were slightly lower than 2020, although
reflected higher emissions trading scheme costs and additional
remediation expenditures at Magnus. Unit operating costs increased
to $20.5/Boe primarily reflecting lower production. Cash generated
by operations increased to $756.9 million, up 33.4% compared to
2020, with free cash flow generation of $396.8 million.
During the year, we successfully refinanced our previous senior
credit facility ('RCF') into a new senior secured debt facility
('RBL') of up to $750.0 million. The strong cash flow performance
and refinancing ultimately led to a simplified debt structure, with
a lower than expected utilisation of the facility, an early
voluntary repayment of $70.0 million, repayments of the BP vendor
loan and Sculptor Capital facility, and enabled the payment of
$250.0 million cash consideration for the Golden Eagle
acquisition.
Environmental, Social and Governance
Environmental
Managing existing assets in a responsible and sustainable manner
is a key part of the energy transition. We recognise that industry,
alongside other key stakeholders such as governments, regulators
and consumers, must contribute to reducing the impact on climate
change of carbon-related emissions. We are committed to playing our
part in the achievement of national emissions reduction targets,
with the Infrastructure and New Energy business having overall
responsibility for delivering the Group's emission reduction
objectives. As outlined earlier, we have made excellent progress in
reducing absolute Scope 1 and 2 emissions during the year and are
significantly ahead of the Group's targets and those set by the UK
Government's North Sea Transition Deal. We continue 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.
EnQuest's Infrastructure and New Energy business is assessing
renewable energy and decarbonisation opportunities using the
existing infrastructure at the Sullom Voe Terminal. We are working
collaboratively with Shetland Island Council, Project ORION and the
Net Zero Technology Centre, to better understand how we can
contribute further to the industry approach to achieving net-zero,
whilst remaining aligned with EnQuest's strategy and Values.
Social - Health and safety
EnQuest's absolute priority has consistently been SAFE Results,
no harm to our people and respect for the environment, and there
remains a strong safety culture throughout the organisation,
clearly evidenced by recording a Group LTI frequency1 of 0.21, an
improvement on 2021 and slightly better than the International
Association of Oil and Gas Producers benchmark of 0.22. We also
continued to reduce the number of reportable hydrocarbon releases
in both the UK and Malaysia. The Group-wide asset integrity review
has brought additional focus to cost allocation in key risk areas
that could impact asset integrity.
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)
Social - People
Improving workforce diversity and inclusion ('D&I') across
the organisation remains a key focus area for the Group. Good
progress has been made with the Group-wide D&I strategy and
associated policy now embedded in the overall strategy of the
business. The D&I strategy includes several targets to improve
female and ethnic minority representation in leadership and
executive roles by 2025. A number of initiatives continued
throughout the year and I was delighted to see EnQuest nominated as
one of three finalists for the 2021 OGUK Diversity & Inclusion
Award. Recognition as a finalist has further reinforced our
commitment to our strategy and direction of travel in relation to
D&I.
Social - Communities
In 2021, we extended the remit of the Remuneration Committee to
include social responsibility, covering the Group's external
support of charitable works and education initiatives. In Malaysia,
we continued to sponsor university students to study STEM-related
subjects and supported the 'IChemE' accreditation of the Chemical
and Process Engineering programme at the National University of
Malaysia. We also sponsored and participated in the programme to
replant 380 mangrove trees covering an approximate wetland area of
900m2 within the Kuala Selangor Nature Park. In the UK, local
community support included financial contributions to charitable
organisations throughout the year and the provision of internship
placements in roles from Upstream to Communications to young
student engineers connected to the Association for Black and
Minority Ethnic Engineers. We also extended our partnership with
the University of Bradford's Professor of Practice in
Sustainability and Energy Futures within the School of Management,
Law and Social Sciences.
2022 performance and outlook
Production performance to the end of February was 50,408 Boepd.
Our full year net production guidance of between 44,000 and 51,000
Boepd is underpinned by our largest well programme since 2014,
including infill drilling and workover campaigns at Magnus, Golden
Eagle and PM8/Seligi which are expected largely to mitigate natural
declines at these fields.
With an enlarged portfolio, increased activity set and higher
emissions and diesel costs as a result of higher market prices,
operating expenditures are expected to be approximately $430
million, while capital expenditure is expected to be around $165
million. Abandonment expense is expected to total approximately $75
million, primarily reflecting well P&A decommissioning
programmes at the Heather/Broom and Thistle/Deveron fields.
Longer-term development
EnQuest's business has been strengthened by the acquisition of
the Golden Eagle asset which has added significant cash-generating
capability to the Group, while the supportive macro environment and
higher oil prices provide the opportunity for continued debt
reduction while selectively investing in its low-cost, short-cycle,
quick payback well portfolio to offset natural declines. The
acquisitions of Bressay and Bentley have added almost 250 MMboe of
2C resources, adding to those already in place at Magnus, Kraken,
PM8/Seligi and PM409, providing EnQuest with longer-term potential
development opportunities. At the same time, the Group will
continue to be disciplined with respect to M&A opportunities to
grow the business further.
With a focus on short-cycle projects, EnQuest can 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's business is
strongly positioned to play an important role in the energy
transition by responsibly optimising production, leveraging
existing infrastructure, delivering a strong decommissioning
performance and exploring new energy and further decarbonisation
opportunities.
Operating review
Upstream operations
2021 Group performance summary
Production of 44,415 Boepd reflected a strong performance at
Kraken and the contribution from Golden Eagle following completion
of the acquisition, offset by topside and well integrity related
outages at Magnus, planned maintenance and a subsea power umbilical
failure at the Greater Kittiwake Area ('GKA') and expected natural
declines across the portfolio. The natural declines were to a large
extent a consequence of the necessary pause in the Group's drilling
programme following materially lower oil prices experienced in 2020
and into 2021.
UK operations
Magnus
2021 performance summary
Production in 2021 was lower than expected at 11,870 Boepd.
Performance was impacted by well integrity issues, topside power
and compression failures, third-party infrastructure outages and
natural decline. A production enhancement programme was undertaken
in the second quarter, including a coil tubing campaign, returning
four wells to service. Repairs to a compressor gearbox failure
which resulted in single train operations during much of the fourth
quarter of 2021 were completed, bringing both trains back into
operation.
2022 outlook
A shutdown of around three to four weeks is planned in the third
quarter to complete scheduled safety-critical activities along with
plant equipment upgrades, while further asset integrity maintenance
and plant opportunities will continue to be assessed and
implemented throughout the year.
It is anticipated that three wells will be drilled in 2022,
largely mitigating natural decline at the field, with a further two
wells expected to be drilled during 2023. With 2C resources of c.35
MMboe, Magnus offers the Group significant low-cost, quick pay-back
drilling opportunities in the medium term.
Kraken
2021 performance summary
Average gross production was within the Group's guidance range
at 31,155 Boepd (21,964 Boepd net). Overall subsurface and well
performance was good with aggregate water cut evolution remaining
in line with expectations and the Floating, Production, Storage and
Offloading ('FPSO') vessel continued to perform well throughout the
year, with top quartile production and water injection efficiency
at 88% and 89%, respectively. During the first half of the year, a
number of opportunistic maintenance activities were successfully
undertaken, allowing for the deferral of the planned shutdown to
2022. However, production was impacted by short duration shutdowns
related to the repair of a subsea tether, an oil heater failure and
natural decline.
During the fourth quarter of 2021, Kraken production reached the
milestones of over 50 million barrels (gross) produced since
inception and the 100th cargo offload.
The Group continues 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 has benefited
from strong pricing in the market and avoids refining-related
emissions.
Near-field drilling and subsea tie-back opportunities continue
to be assessed. A successful 3D seismic campaign was completed in
July, providing valuable data for the Group to evaluate fully the
development potential of the western area of the field, in addition
to supporting ongoing optimisation of the main Kraken field,
including potential infill opportunities.
2022 outlook
Over the summer, a two-week shutdown is planned to undertake
safety-critical maintenance work.
For the full year, Kraken production is expected to be between
22,000 Boepd and 26,000 Boepd (15,500 Boepd to 18,500 Boepd net),
reflecting the planned shutdown and natural decline.
Evaluation of the 3D seismic is ongoing. The Group is currently
assessing main field side-track drilling opportunities along with
further opportunities within the Pembroke and Maureen sands.
Golden Eagle
2021 performance summary
The acquisition of a 26.69% interest in Golden Eagle was
completed on 22 October 2021, contributing 1,701 Boepd to EnQuest
on an annualised basis (10,220 Boepd on a pro forma basis). This
reflected high uptime and continued good well performance following
the infill drilling campaign earlier in the year.
2022 outlook
A two-well drilling campaign is scheduled late in the year and
preparations are being undertaken for further infill drilling in
2023. The asset offers further development opportunities subsea and
platform infill drilling.
Other Upstream assets
2021 performance summary
Production in 2021 averaged 3,685 Boepd, slightly below
expectations. At GKA, which includes Scolty/Crathes, the reduction
was driven by a planned four-week shutdown, the failure of a power
umbilical to the Mallard and Gadwall wells, gas compression outages
and natural decline. The power umbilical was successfully replaced
as planned in September, restoring Mallard and Gadwall to
production.
At Alba, performance continued in line with the Group's
expectations.
At Bressay, detailed analysis of existing reservoir data and an
assessment of potential development options, one of which is a
potential tie-back to Kraken, continued with strong partner
engagement throughout.
2022 outlook
At GKA, a two-week shutdown is planned during the second
quarter, in line with a short shutdown of related
infrastructure.
At Alba, the partners expect to begin a continuous 2022-2024
drilling programme during the third quarter of 2022. The first
wells from this programme are expected to come online during
2023.
At Bressay, it is expected that a field development plan will be
developed during 2022, while at Bentley, initial evaluation of the
development potential are due to commence in the first quarter of
2022.
Malaysia operations
2021 performance summary
In Malaysia, average production of 5,028 Boepd was 21.9% lower
than 2020. This reduction primarily reflected the continued impacts
of the detached riser system at the Seligi Alpha platform and the
impact of COVID-19 on the execution of various work scopes,
although production was in line with expectations following an
acceleration of initial production recovery activities in the early
part of the year.
In December, the new riser pipeline was successfully laid on the
seabed, although final completions were delayed by the late arrival
and subsequent availability of the third-party dive support vessel
('DSV'). The riser pipeline was fully installed and commissioned in
the first quarter of 2022.
On Block PM409, an area containing several undeveloped
discoveries and situated close to the Group's existing PM8/Seligi
PSC hub, geotechnical studies have been completed in preparation
for future appraisal drilling.
2022 outlook
A two-week shutdown at Seligi to undertake asset integrity and
maintenance activities is planned for the summer, which will help
to improve reliability and efficiency at the field.
EnQuest has significant 2P reserves and 2C resources of c.20
MMboe and c.86 MMboe, respectively. With a number of low-cost
drilling and workover targets having been identified at PM8/Seligi,
the Group is expected to drill four infill wells and four workovers
during 2022 and plans an annual drilling and workover programme for
a number of years thereafter. The Group continues to assess the
opportunity to develop the additional gas resource at PM8/Seligi to
meet forecast Malaysian demand. At PM409, a well proposal for
drilling in 2023 is being developed for approval by the
partnership, while a site survey and other associated preparatory
activities will also be undertaken.
Decommissioning
2021 performance summary
Average production of 167 Boepd reflected the decision to cease
production at the Dons in March 2021. In April 2021, the Northern
Producer Floating Production Facility departed the Dons and was
handed back to its owners.
At Heather/Broom, the well plug and abandonment ('P&A')
programme continued on schedule, while the topsides decommissioning
programme was approved by the Secretary of State and topside
removal contractors submitted initial tenders in the fourth
quarter.
At Thistle/Deveron, the first phase of the platform
re-habitation was successfully completed in June, in line with
expectations. The subsea integrity campaign concluded in September
and platform reactivation and hydrocarbon removal was completed in
October.
The EnQuest Producer FPSO remains in warm stack at Nigg while
the Group continues to evaluate options.
2022 outlook
At Heather, the well P&A programme is ongoing, with 16 well
abandonments scheduled during the year. The drilling rig at Thistle
will shortly be reactivated, with 16 wells also anticipated to be
abandoned as part of this year's well P&A programme which is
planned to start in April. It is expected that topsides and jacket
removal contracts will be awarded for both Heather and Thistle
later in 2022.
Following Cessation of Production ('CoP') at Alma/Galia, the
Dons and Broom, preparations continue ahead of the anticipated
commencement of subsea well P&A and infrastructure removal at
all three fields, with the target to be execution-ready by the end
of 2023.
Infrastructure and New Energy
To support the ongoing transformation of SVT and EnQuest's
energy transition ambitions, the Group established an
Infrastructure and New Energy business division in August 2021.
2021 performance summary
At the Sullom Voe Terminal ('SVT') and its related
infrastructure, the delivery of safe and reliable performance
enabled 99.9% service availability during the year. The Group
continued to work in close collaboration with its stakeholders to
ensure the terminal meets existing and future customer needs, while
remaining focused on simplification and cost management.
In pipelines, good progress was made undertaking planned repair
and remediation work on delivery infrastructure relating to Kraken,
Magnus and Thistle, in addition to in-line pipeline inspection
evaluations at GKA. These activities will ensure continued smooth
operations across the Group's assets.
2022 outlook
EnQuest remains focused on maintaining safe and reliable
operations at the terminal and in its pipeline operations, with a
significant asset integrity programme planned. Working closely with
SVT co-owners and other stakeholders, EnQuest is developing
cost-effective and efficient plans to prepare and repurpose the
site in line with the Group's new energy ambitions. Engagement with
a variety of stakeholders, including potential technical and
financial partners, Shetland Island Council, Project ORION and the
Net Zero Technology Centre is ongoing.
Financial review
All figures quoted are in US Dollars and relate to Business
performance unless otherwise stated. Please note the below overview
includes restated comparatives. See note 2 for further details.
The Group made good progress on its strategic aims during 2021.
Supported by higher oil prices and capital discipline, EnQuest
generated strong free cash flow of $396.8 million, up 88.5%
compared to 2020, which, along with the signing of a new senior
secured credit facility ('RBL'), enabled the Group to simplify its
capital structure, facilitate the Golden Eagle acquisition and
reduce overall net debt.
Production on a working interest basis decreased by 24.9% to
44,415 Boepd, compared to 59,116 Boepd in 2020. High uptime at
Kraken, the contribution from Golden Eagle and the accelerated
recovery of wells at PM8/Seligi was offset by underperformance at
Magnus.
Revenue for 2021 was $1,320.3 million, 54.4% higher than in 2020
($855.1 million) reflecting the materially higher realised prices
partially offset by lower volumes. The Group's commodity hedge
programme resulted in realised losses of $67.7 million in 2021
(2020: losses of $6.1 million). See note 27 for further information
on the Group's hedging programmes.
The Group's operating expenditures of $321.0 million were
marginally lower than 2020 ($328.6 million), although unit
operating costs (excluding hedging) increased to $20.5/Boe (2020:
$15.2/Boe) reflecting lower production.
Other costs of operations of $211.5 million were materially
higher than in 2020 ($53.5 million), principally as a result of
higher Magnus-related third-party gas purchases following the
increase in associated market prices.
With the Group moving into an overlift position during the year,
a charge relating to the Group's lifting position and inventory of
$62.3 million was recognised (2020: credit of $34.8 million).
Adjusted EBITDA for 2021 was $742.9 million, up 34.9% compared
to 2020 ($550.6 million), primarily as a result of higher
revenue.
2021 2020
$ million $ million
-------------------------------------------------------------------- ----------- -----------
Profit/(loss) from operations before tax and finance income/(costs) 443.2 (20.0)
-------------------------------------------------------------------- ----------- -----------
Depletion and depreciation 313.1 445.9
-------------------------------------------------------------------- ----------- -----------
Change in provisions (13.1) 95.2
-------------------------------------------------------------------- ----------- -----------
Change in well inventories 0.1 24.9
-------------------------------------------------------------------- ----------- -----------
Net foreign exchange (gain)/loss (0.4) 4.6
-------------------------------------------------------------------- ----------- -----------
Adjusted EBITDA 742.9 550.6
-------------------------------------------------------------------- ----------- -----------
EnQuest's net debt decreased by $57.7 million to $1,222.0
million at 31 December 2021 (31 December 2020: $1,279.7 million).
This includes $225.0 million of payment in kind ('PIK') interest
that has been capitalised to the principal of the facilities
pursuant to the terms of the Group's November 2016 refinancing (31
December 2020: $205.8 million) (see note 18 for further
details).
Net debt/(cash)1
------------------------
31 December 31 December
2021 2020
$ million $ million
------------------------------------------------- ----------- -----------
Bonds 1,083.8 1,048.3
------------------------------------------------- ----------- -----------
Multi-currency revolving credit facility ('RCF') - 377.3
------------------------------------------------- ----------- -----------
Sculptor Capital facility - 67.7
------------------------------------------------- ----------- -----------
Senior secured debt facility ('RBL') 415.0 -
------------------------------------------------- ----------- -----------
SVT working capital facility 9.9 9.2
------------------------------------------------- ----------- -----------
Cash and cash equivalents (286.7) (222.8)
------------------------------------------------- ----------- -----------
Net debt 1,222.0 1,279.7
------------------------------------------------- ----------- -----------
Note:
1 See reconciliation of net debt within the 'Glossary - Non-GAAP measures' starting on page 66
In June, the Group announced that it had signed a new RBL of
$600.0 million with an additional amount of $150.0 million for
letters of credit for up to seven years, subject to the timing of
the refinancing of the bonds. Also in June, the Group repaid the
outstanding principal and interest on the Sculptor Capital facility
from free cash flow.
In July 2021, $360.0 million was drawn down from the Group's new
RBL facility. The proceeds were used to repay the entire
outstanding balance on the RCF, which at the time of repayment was
$354.5 million, including PIK and accrued interest. Also in July,
$58.7 million, representing the full amount of the outstanding
principal and interest on the Magnus vendor loan, was repaid and
the Group successfully completed an equity raise with net proceeds
of $47.2 million.
In October 2021 and following shareholder approval of the Golden
Eagle acquisition, a further $125.0 million was drawn down against
the RBL, partially to fund the $250.0 million cash
consideration.
In December 2021, EnQuest made a voluntary early repayment of
$70.0 million on the RBL, with further early voluntary repayments
totalling $85.3 million made in the first quarter of 2022.
The Group continues to have unrestricted access to its UK North
Sea corporate tax losses, subject only to generating suitable
future profits, which at the end of the year decreased to $3,011.0
million (2020: $3,183.9 million). The Group paid cash corporate
income tax following the acquisition of Golden Eagle by the Group
and on the Malaysian assets, which will continue throughout the
life of the Production Sharing Contract. In the current
environment, no significant corporation tax or supplementary charge
is expected to be paid on UK operational activities for the
foreseeable future.
Income statement
Revenue
On average, market prices for crude oil in 2021 were
significantly higher than in 2020. The Group's average realised oil
price excluding the impact of hedging was $73.0/bbl, 75.5% higher
than in 2020 ($41.6/bbl). Revenue is predominantly derived from
crude oil sales, which totalled $1,139.2 million, 46.1% higher than
in 2020 ($779.9 million), reflecting the significantly higher oil
prices, offset by lower production. Revenue from the sale of
condensate and gas, primarily in relation to the onward sale of
third-party gas purchases not required for injection activities at
Magnus, was $244.1 million (2020: $60.5 million), as a result of
the significantly higher gas prices. Tariffs and other income
generated $4.7 million (2020: $20.8 million). The Group's commodity
hedges and other oil derivatives contributed $67.7 million of
realised losses (2020: losses of $6.1 million). The Group's average
realised oil price including the impact of hedging was $68.6/bbl in
2021, 66.4% higher than 2020 ($41.3/bbl).
Note: For the reconciliation of realised oil prices see
'Glossary - Non-GAAP measures' starting on page 66
Cost of sales1
2021 2020
$ million $ million
--------------------------------------------------------- ----------- -----------
Production costs 292.3 265.5
--------------------------------------------------------- ----------- -----------
Tariff and transportation expenses 39.4 63.7
--------------------------------------------------------- ----------- -----------
Realised (gain)/loss on derivatives related to operating
costs (10.7) (0.6)
--------------------------------------------------------- ----------- -----------
Operating costs 321.0 328.6
--------------------------------------------------------- ----------- -----------
(Credit)/charge relating to the Group's lifting position
and inventory 62.3 (34.8)
--------------------------------------------------------- ----------- -----------
Depletion of oil and gas assets 305.6 438.2
--------------------------------------------------------- ----------- -----------
Other cost of operations 211.5 53.5
--------------------------------------------------------- ----------- -----------
Cost of sales 900.4 785.5
--------------------------------------------------------- ----------- -----------
Unit operating cost2 $/Boe $/Boe
--------------------------------------------------------- ----------- -----------
- Production costs 18.1 12.3
--------------------------------------------------------- ----------- -----------
- Tariff and transportation expenses 2.4 2.9
--------------------------------------------------------- ----------- -----------
Average unit operating cost 20.5 15.2
--------------------------------------------------------- ----------- -----------
Notes:
1 See reconciliation of alternative performance measures within
the 'Glossary - Non-GAAP measures' starting on page 66
2 Calculated on a working interest basis
Cost of sales were $900.4 million for the year ended 31 December
2021, 14.6% higher than in 2020 ($785.5 million).
Operating costs decreased by $7.6 million, primarily reflecting
reduced tariff and transportation costs due to lower production in
2021. This was largely offset by higher production costs driven by
materially higher emission allowances costs, lower lease charter
credits reflecting higher uptime at Kraken as a result of the
continued strong performance of the FPSO, and remediation costs at
Magnus. Unit operating costs (excluding hedging) increased by 34.9%
to $20.5/Boe (2020: $15.2/Boe), reflecting lower production. Unit
operating costs including hedging were $19.8/Boe (2020:
$15.2/Boe).
The charge relating to the Group's lifting position and
inventory was $62.3 million (2020: credit of $34.8 million). This
reflects a switch to an $18.0 million net overlift position at 31
December 2021 from a $3.0 million net underlift position at 31
December 2020. The charge for the year is also impacted by the
post-acquisition revaluation of the underlift position at Golden
Eagle. Depletion expense of $305.6 million was 30.3% lower than in
2020 ($438.2 million), mainly reflecting lower production.
Other cost of operations of $211.5 million were materially
higher than in 2020 ($53.5 million), principally as a result of
higher Magnus-related third-party gas purchase cost following the
increase in associated market prices, offset by a partial release
of the inventory provision.
Other income and expenses
Net other income of $23.7 million (2020: net other expense of
$85.3 million) is primarily due to a net decrease of $13.1 million
related to the decommissioning provision of the fully impaired
non-producing assets.
Finance costs
Finance costs of $169.5 million were 5.7% lower than in 2020
($179.8 million). This decrease was primarily due to a reduction of
$12.6 million in interest charges associated with the Group's loans
(2021: $20.2 million; 2020: $32.8 million) and a $4.4 million
decrease in bond interest (2021: $69.1 million; 2020: $73.5
million). Other finance costs included lease liability interest of
$45.4 million (2020: $50.9 million), $16.9 million on unwinding of
discount on decommissioning and other provisions (2020: $15.3
million), $13.6 million amortisation of arrangement fees for
financing facilities and bonds, reflecting the accelerated
amortisation of the Sculptor Capital facility fees and the fees
associated with the Group's RBL facility (2020: $5.4 million) and
other financial expenses of $4.3 million (2020: $2.0 million),
primarily being the cost for surety bonds to provide security for
decommissioning liabilities.
Taxation
The tax charge for 2021 of $53.7 million (2020: $172.5 million
tax credit), excluding exceptional items, is mainly due to the
taxable profits generated in the year exceeding 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
gain of $156.7 million have been disclosed separately for the year
ended 31 December 2021 (2020: loss of $443.8 million).
Revenue included unrealised losses of $54.5 million in respect
of the mark-to-market movement on the Group's commodity contracts
(2020: unrealised gains of $8.8 million). Cost of sales included
expenses of $7.3 million in relation to a provision for a contract
dispute with a third-party contractor.
Non-cash net impairment reversal of $39.7 million (2020: $422.5
million charge) on the Group's oil and gas assets arises from an
increase in the near and medium-term oil price and updated asset
profiles.
Other income included a $140.1 million gain in relation to the
fair value recalculation of the Magnus contingent consideration
reflecting a forecast reduction in Magnus future cash flows (2020:
$138.2 million gain). Other finance costs mainly relate to the
unwinding of contingent consideration from the acquisition of
Magnus and associated infrastructure and interest charged on the
vendor loan of $58.4 million (2020: $77.3 million).
A net tax credit of $78.2 million (2020: charge of $76.4
million) has been presented as exceptional, representing the
non-cash recognition of undiscounted deferred tax assets of $104.5
million given the Group's acquisition of Golden Eagle and the
Group's higher oil price assumptions, partially offset by the tax
impact of the remeasurements and exceptional items. EnQuest
continues to have unrestricted access to its UK North Sea corporate
tax losses of $3,011.0 million at 31 December 2021, subject only to
generating suitable future profits.
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 its
Business performance results and Remeasurements and exceptional
items, both of which are explained above.
IFRS revenue reflects Business performance revenue, but it is
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 previously. 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, the Group's IFRS
profit from operations before tax and finance costs was $580.0
million (2020: loss of $310.1 million), IFRS profit before tax was
$352.4 million (2020: loss of $566.0 million), and IFRS profit
after tax of $377.0 million (2020: loss of $469.9 million).
Earnings per share
The Group's Business performance basic earnings per share was
12.7 cents (2020 loss per share: 1.6 cents) and diluted earnings
per share was 12.5 cents (2020 loss per share: 1.6 cents).
The Group's reported basic earnings per share was 21.7 cents
(2020 loss per share: 29.0 cents) and reported diluted earnings per
share was 21.4 cents (2020 loss per share: 29.0 cents).
Cash flow and liquidity
Net debt at 31 December 2021 amounted to $1,222.0 million,
including PIK of $225.0 million, compared with net debt of $1,279.7
million at 31 December 2020, including PIK of $205.8 million. The
movement in net debt was as follows:
$ million
------------------------------------------------ ---------
Net debt 1 January 2021 (1,279.7)
------------------------------------------------ ---------
Net cash flows from operating activities 674.1
------------------------------------------------ ---------
Cash capital expenditure (51.8)
------------------------------------------------ ---------
Acquisition costs (258.6)
------------------------------------------------ ---------
Repayments on Magnus financing and profit share (74.7)
------------------------------------------------ ---------
Finance lease payments (136.7)
------------------------------------------------ ---------
Net interest and finance costs paid (62.8)
------------------------------------------------ ---------
Non-cash capitalisation of interest (36.4)
------------------------------------------------ ---------
Fees related to the RBL facility (29.1)
------------------------------------------------ ---------
Net equity raise proceeds 47.2
------------------------------------------------ ---------
Other movements (13.5)
------------------------------------------------ ---------
Net debt 31 December 2021 1 (1,222.0)
------------------------------------------------ ---------
Note:
1 See reconciliation of alternative performance measures within
the 'Glossary - Non-GAAP measures' starting on page 66
The Group's reported net cash flows from operating activities
for the year ended 31 December 2021 were $674.1 million, up 29.3%
compared to 2020 ($521.4 million). The main drivers for this
increase were materially higher oil revenue offset by lower
production and increased decommissioning spend.
Cash outflow on capital expenditure is set out in the table
below:
Year ended Year ended
31 December 31 December
2021 2020
$ million $ million
--------------------------- ------------ ------------
North Sea 35.9 127.0
--------------------------- ------------ ------------
Malaysia 14.8 4.4
--------------------------- ------------ ------------
Exploration and evaluation 1.1 -
--------------------------- ------------ ------------
51.8 131.4
--------------------------- ------------ ------------
Cash capital expenditure in 2021 primarily related to Magnus
production enhancement campaigns and the PM8/Seligi pipeline
replacement.
Balance sheet
The Group's total asset value has increased by $503.0 million to
$4,365.6 million at 31 December 2021 (2020: $3,862.6 million),
mainly due to the acquisition of Golden Eagle and an increase in
trade and other receivables. Net current liabilities have decreased
to $333.1 million as at 31 December 2021 (2020: $536.9 million).
Included in the Group's net current liabilities are $30.5 million
of estimated future obligations where settlement is subject to the
financial performance of Magnus (2020: $73.9 million).
Property, plant and equipment ('PP&E')
PP&E has increased by $188.1 million to $2,822.0 million at
31 December 2021 from $2,633.9 million at 31 December 2020 (see
note 10). This increase encompasses the Golden Eagle asset
acquisition of $386.2 million, other capital additions to PP&E
of $80.7 million, and non-cash net impairment reversals of $39.7
million, offset by depletion and depreciation charges of $313.0
million and a net decrease of $2.7 million for changes in estimates
for decommissioning and other provisions.
The PP&E capital additions during the year, including
capitalised interest, are set out in the table below:
$ million
---------- ---------
North Sea 449.5
---------- ---------
Malaysia 17.4
---------- ---------
466.9
---------- ---------
Trade and other receivables
Trade and other receivables increased by $177.4 million to
$296.1 million at 31 December 2021 (2020: $118.7 million). The
increase is mainly attributable to the timing of receipts for
cargoes lifted in December and the impact of gas prices on accrued
gas sales.
Cash and net debt
The Group had $286.7 million of cash and cash equivalents at 31
December 2021 and $1,222.0 million of net debt, including PIK of
$225.0 million (2020: $222.8 million, $1,279.7 million and $214.2
million, respectively).
Net debt comprises the following liabilities:
* $256.2 million principal outstanding on the GBP155.0 million retail
bond, including interest capitalised as PIK of $47.9 million (2020:
$249.2 million and $39.4 million, respectively);
* $827.2 million principal outstanding on the high yield bond, including
interest capitalised as PIK of $177.2 million (2020: $799.2 million
and $149.2 million, respectively);
* $415.0 million drawn down on the RBL (2020: $377.3 million of the
RCF, comprising amounts drawn down of $360.0 million and interest
capitalised as PIK of $17.3 million); and
* $9.9 million relating to the SVT working capital facility (2020:
$9.2 million).
Provisions
The Group's decommissioning provision increased by $57.5 million
to $835.7 million at 31 December 2021 (2020: $778.2 million). The
movement is due to $119.3 million of additions relating to the
Golden Eagle acquisition and $15.9 million unwinding of discount,
partially offset by utilisation of $55.6 million for
decommissioning carried out in the year and a reduction in
estimates of $22.1 million.
Other provisions, including the Thistle decommissioning
provision, decreased by $3.0 million in 2021 to $59.2 million
(2020: $62.2 million). The Thistle decommissioning provision of
$43.9 million (2020: $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.
Contingent consideration
The contingent consideration related to the Magnus acquisition
decreased by $156.7 million. In 2021, EnQuest paid $75.0 million to
BP (2020: $74.0 million), which included the early repayment of the
entire $74.7 million outstanding balance (including interest) of
the 75% interest vendor loan. A change in fair value estimate
credit of $140.1 million (2020: $138.2 million) and finance costs
of $58.4 million (2020: $77.3 million) were recognised in the
year.
The Group recognised $44.7 million contingent consideration
payable associated with the acquisition of Golden Eagle which
completed in October 2021. The balance increased to $45.2 million
at 31 December 2021.
Income tax
The Group had a net income tax payable of $3.6 million (2020:
$5.6 million receivable) 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 increased from $653.4
million at 31 December 2020 to $699.6 million at 31 December 2021.
This is driven by non-cash recognition of undiscounted deferred tax
assets due to increased future taxable profits following the
acquisition of Golden Eagle. EnQuest continues to have unrestricted
access to its UK corporate tax losses carried forward at 31
December 2021 amounting to $3,011.0 million (31 December 2020:
$3,189.9 million), subject only to generating suitable future
profits. During the year the Group restated the 2020 deferred tax
asset position, see note 2 for further details.
Trade and other payables
Trade and other payables of $420.5 million at 31 December 2021
are $165.4 million higher than at 31 December 2020 ($255.2
million). The full balance of $420.5 million is payable within one
year. This increase is driven by the increase in the Group's
overlift position and the impact of higher market prices on UK
emission allowances and Magnus-related gas purchases.
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.
The health, safety and wellbeing of the Group's employees is its
top priority and it continues to monitor actively the impact on
operations from COVID-19. 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 is cognisant of the ongoing risks presented by the
evolving situation. 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.
During 2021, the Group signed a new senior secured borrowing
base debt facility (the 'RBL') of $600.0 million and an additional
amount of $150.0 million for letters of credit for up to seven
years, subject to refinancing the Group's existing high yield
bonds. The RBL is initially repaid based on an amortisation
schedule and via a cash sweep mechanism, whereby any unrestricted
cash in excess of $75.0 million is swept to repay outstanding
amounts at calendar quarter ends. Application of the amortisation
schedule ensures the RBL is fully repaid by June 2023.
Upon refinancing of the Group's High Yield Bond, the maturity of
the RBL is extended to seven years from its signing date (11 June
2021), or the point at which the remaining economic reserves for
all borrowing base assets are projected to fall below 25% of the
initial economic reserves forecast, if earlier.
At 31 December 2021, $415.0 million was drawn on the RBL, with
early voluntary repayments of $85.0 million made in the first
quarter of 2022.
The Group continues to explore options to refinance its Retail
and High Yield Bonds ahead of maturity in October 2023. For the
purposes of assessing going concern it is assumed that the
refinancing of the bonds occurs outside of the going concern
period. However, in the scenario that the Group concluded a
successful refinancing of the bonds within the next 12 months, then
the going concern basis at the date of release of this report would
also be considered appropriate.
The Group's latest approved business plan underpins management's
base case ('Base Case') and is in line with the Group's production
guidance and uses oil price assumptions of $75.0/bbl for 2022 and
$70.0/bbl for 2023, adjusted for hedging activity undertaken.
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 $67.5/bbl for 2022 and $63.0/bbl for 2023;
* Production risking of c.5% for 2022 and 2023; and
* 2.5% increase in operating costs.
The Base Case and Downside Case indicate that the Group is able
to operate as a going concern and remain covenant compliant 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 liquidity breakeven price in the going concern
period being less than $60.0/bbl in order to maintain a minimum
unrestricted cash balance of above $50.0 million across all periods
(as required by the RBL).
Should circumstances arise that differ from the Group's
projections, the Directors believe that a number of mitigating
actions, including 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.
After making appropriate 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 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 2025. The viability assumptions are
consistent with the going concern assessment, with the additional
inclusion of an oil price of $70.0/bbl for the remainder of 2023
and 2024, a longer-term price of $60.0/bbl from 2025 and
refinancing of both the High Yield and Retail Bonds in the second
quarter of 2023. This assessment has taken into account the Group's
financial position as at March 2022, its 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, which includes potential impacts from climate
change concerns and related regulatory developments, and the
actions management are taking to mitigate these risks are outlined
on pages 16 to 26. 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 and
includes the maturation of both its High Yield and Retail bonds.
Based on the Group's projections, including refinancing 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 2025.
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 has 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 prices would adversely affect the Group's
operations and financial condition. To mitigate oil price
volatility, the Directors have hedged a total of 8.6 MMbbls for
2022 primarily using costless collars, with an average floor price
of c.$62.6/bbl and an average ceiling price of c.$77.6/bbl. For
2023, the Group has hedged a total of 3.5 MMbbls with an average
floor price of c.$57.5/bbl and an average ceiling of c.$77.1/bbl.
The Directors, in line with Group policy and the terms of its RBL
facility, 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 bonds.
The maturity date of the existing $827 million High Yield Bond
and the GBP190 million Retail Bonds (both figures at year end 2021)
is October 2023. The application of the current amortisation
schedule on the RBL ensures this is fully repaid by June 2023. In
assessing viability, 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 Base Case oil price assumptions outlined above, the total
amount of the High Yield Bond and Retail Bonds outstanding at
October 2023 would be unchanged from year end 2021, as interest is
payable in cash if 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
$65.0/bbl. If oil prices were to be lower than the Group's
assumptions, then a refinancing 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 2025.
Accordingly, the Directors therefore support this viability
statement.
Risks and uncertainties
Management of risks and uncertainties
Consistent with the Group's purpose, the Board has articulated
EnQuest's strategic vision to be the operator of choice for
maturing and underdeveloped hydrocarbon assets. EnQuest aims to
responsibly optimise production, leverage existing infrastructure,
deliver a strong decommissioning
performance and explore new energy and further decarbonisation
opportunities. It
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 those which can 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 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 culture of risk management 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 Group's risk appetite annually in light of
changing market conditions and the Group'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 Group'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 macroeconomic themes may
influence its principal risks. These are factors which the Group
should be cognisant of when developing its strategy. They include,
for example, long-term supply and demand trends for oil and gas and
renewable energy, 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, the Group has established an
Infrastructure and New Energy business to assess new energy and
decarbonisation opportunities, initially focused on using the
existing infrastructure at the Sullom Voe Terminal. 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 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.
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 2021
to the date of this report and carried out a robust assessment of
the Group'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 identify quickly, escalate
and appropriately manage emerging risks.
During 2021, work was continued to enhance the integration of
these risk registers and automate the process 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, which are now integrated into
the Group's internal audit programme for review.
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
COVID-19
As a responsible operator, EnQuest continues to monitor the
evolving situation and consequent risks with regard to the COVID-19
pandemic, recognising it could 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.
Appetite
The Group's risk appetite for COVID-19 is reported against the
Group's impacted principal risks.
Mitigation
The Group continues to work 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 biggest risk related to COVID-19 is the impact on oil prices
if movement restrictions impact the demand for oil. See 'Oil and
gas price' risk on page 19 for more information on how the Group
mitigates against price risk.
Risk
Climate change
The Group recognises that climate change concerns and related
regulatory developments could impact a number of the Group's
principal risks, such as oil price, financial, reputational and
fiscal and government take risks, which are disclosed later in this
report.
Appetite
EnQuest recognises that the oil and gas industry, alongside
other key stakeholders such as governments, regulators and
consumers, must all play a part in reducing the impact of
carbon-related emissions on climate change, and is committed to
contributing positively towards the drive to net-zero.
The Group's risk appetite for climate change risk is reported
against the Group's impacted principal risks.
Mitigation
Mitigations against the Group's principal risks potentially
impacted by climate change are reported later in this report.
The Group endeavours to reduce emissions through improving
operational performance, minimising flaring and venting where
possible, and applying appropriate and economic improvement
initiatives, noting the ability to reduce carbon emissions will be
constrained by the original design of later-life assets.
EnQuest has reported on all of the greenhouse gas emission
sources within its operational control required under the Companies
Act 2006 (Strategic Report and Directors' Reports) Regulations 2013
and The Companies (Directors' Report) and Limited Liability
Partnerships (Energy and Carbon Report) Regulations 2018.
The Group has committed to a 10% reduction in Scope 1 and 2
emissions over three years, from a year-end 2020 baseline, with the
achievement linked to reward. Progress is reported to the Safety,
Climate and Risk Committee of the Board in relation to progress of
emission reductions, identification of economically viable
emissions savings opportunities across the Group's portfolio of
assets, aligned to the emissions management strategy.
During 2021, the Group established an Infrastructure and New
Energy business that is responsible for delivering the Group's
emission reduction objectives in line with Group and industry
targets and advancing new energy and decarbonisation
opportunities.
The Group's focus on short-cycle investments drives an inherent
mitigation against the potential impact of 'stranded assets'.
Risk
Evolving geopolitical situation
Having assessed its commercial and IT security arrangements, the
Group does not consider it has a material adverse exposure to the
geopolitical situation with respect to the sanctions imposed on
Russia, although recognises the evolving situation is causing oil
price volatility. The Group will continue to monitor its position
to ensure it remains compliant with any sanctions in place.
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 Group, 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 (see 'Oil and
gas prices' risk on page 19), 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 19 and 'Subsurface
risk and reserves replacement' on page 22).
Risk
Health, Safety and Environment ('HSE')
Oil and gas development, production and exploration activities
are by their very nature complex, with HSE risks covering many
areas, including major accident hazards, personal health and
safety, compliance with regulatory requirements, asset integrity
issues and potential environmental impacts, including those
associated with climate change.
Potential impact
Medium (2020 Medium)
Likelihood
Medium (2020 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 and incurs substantial costs in complying with HSE
requirements. The Group's overall record on HSE has been strong,
albeit impacted by regulatory challenges in relation to the
management of the annual flare consent on Magnus and the receipt of
improvement notices from the Health and Safety Executive.
There remains a risk to the availability of competent people
given the potential impacts of COVID-19.
Appetite
The Group's principal aim is SAFE Results with no harm to people
and respect for the environment. Should operational results and
safety ever come into conflict, employees have a responsibility to
choose safety over operational results. Employees are empowered to
stop operations for safety-related reasons.
The Group's desire is to maintain upper quartile HSE performance
measured against suitable industry metrics.
In 2021, EnQuest achieved a top quartile Lost Time Incident
frequency rate and hydrocarbon release frequency rate in the
UK.
Mitigation
The Group maintains, in conjunction with its core contractors, a
comprehensive programme of assurance activities and has undertaken
a series of deep dives into the Risk Bowties that have demonstrated
the robustness of the management process and identified
opportunities for improvement. A Group-aligned HSE continuous
improvement programme is in place, promoting a culture of
engagement and transparency in relation to HSE matters. HSE
performance is discussed at each Board meeting and the mitigation
of HSE risk continues to be a core responsibility of the Safety,
Climate and Risk Committee. During 2021, the Group continued to
focus on the control of major accident hazards and 'SAFE
Behaviours'.
In addition, the Group has positive and transparent
relationships with the UK Health and Safety Executive and
Department for Business, Energy & Industrial Strategy, and the
Malaysian regulator, Malaysia Petroleum Management.
EnQuest's HSE Policy is fully integrated across its operated
sites and this has enabled an increased focus on HSE. There is a
strong assurance programme in place to ensure EnQuest complies with
its Policy and principles and regulatory commitments.
In 2021, an independent asset integrity review was undertaken
across the Group. This allowed for a deep review of asset integrity
looking at people, plant and process aspects in relation to the
management of risk. The outcome was a more transparent and robust
approach to cost allocation to key risk threats that could impact
asset integrity.
The Group continues to monitor the evolving situation with
regard to the impacts of COVID-19 in conjunction with a variety of
stakeholders, including industry and medical organisations.
Appropriate actions will continue to be implemented in accordance
with expert advice and the level of risk.
Risk
Oil and gas prices
A material decline in oil and gas prices adversely affects the
Group's operations and financial condition as the Group's revenue
depends substantially on oil prices.
Potential impact
High (2020 High)
Likelihood
High (2020 High)
The potential impact and likelihood remain high, reflecting the
uncertain economic outlook, including possible impacts from
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.
Appetite
The Group recognises that considerable exposure to this risk is
inherent to its business but is committed to protecting cash flows
in line with the terms of its reserve based lending facility.
Mitigation
This risk is being mitigated by a number of measures.
As an operator of mature producing assets with limited appetite
for exploration, the Group 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.
The Group monitors oil price sensitivity relative to its capital
commitments. The terms of the Group's reserve based lending
facility also requires hedging of its production (see page 60). The
Group has a policy which allows hedging of its production (see page
60). As at 23 March 2022, the Group had hedged approximately 12.1
MMbbls for 2022 and 2023. This ensures that the Group will receive
a minimum oil price for some of its production.
In order to develop its resources, the Group needs to be able to
fund the required investment. The Group will therefore regularly
review and implement suitable policies to hedge against the
possible negative impact of changes in oil prices.
The Group has an established in-house trading and marketing
function to enable it to enhance its ability to mitigate the
exposure to volatility in oil prices.
Further, as described previously, the Group's focus on
production efficiency supports mitigation of a low oil price
environment.
Risk
Production
The Group's production is critical to its success and is subject
to a variety of risks, including: subsurface uncertainties;
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 (2020 High)
Likelihood
Medium (2020 Medium)
There has been no material change in the potential impact or
likelihood. Operational issues at Magnus, which resulted in the
Group lowering its production guidance for 2021, have been offset
by the Group acquiring a non-operated interest in the Golden Eagle
area in the UK North Sea.
Appetite
Since production efficiency and meeting production targets are
core to EnQuest's business, the Group seeks to maintain a high
degree of operational control over production assets in its
portfolio. EnQuest has a very low tolerance for operational risks
to its production (or the support systems that underpin
production).
Mitigation
The Group's programme of asset integrity and assurance
activities provide leading indicators of significant potential
issues, which may result in unplanned shutdowns, or which may in
other respects have the potential to undermine asset availability
and uptime. The Group continually assesses the condition of its
assets and operates extensive maintenance and inspection programmes
designed to minimise the risk of unplanned shutdowns and
expenditure.
The Group monitors both leading and lagging KPIs in relation to
its maintenance activities and liaises closely with its downstream
operators to minimise pipeline and terminal production impacts.
Production efficiency is continually monitored with losses being
identified and remedial and improvement 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.
The Sullom Voe Terminal has a good safety record, and its safety
and operational performance levels are regularly monitored and
challenged by the Group and other terminal owners and users to
ensure that operational integrity is maintained. Further, EnQuest
is committed to transforming the Sullom Voe Terminal to ensure it
remains competitive and well placed to maximise its useful economic
life and support the future of the North Sea.
The Group actively continues to explore the potential of
alternative transport options and developing hubs that may provide
both risk mitigation and cost savings.
The Group also continues to consider new opportunities for
expanding production.
Risk
Financial
Inability to fund financial commitments or maintain adequate
cash flow and liquidity and/or reduce costs.
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 its existing credit facilities.
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 to 16.
Potential impact
High (2020 High)
Likelihood
High (2020 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 successfully refinanced its existing term loan and
revolving credit facility during 2021 and completed the Golden
Eagle area acquisition.
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
continue to trend higher along with insurers' reluctance to provide
surety bonds for decommissioning, thereby requiring the Group to
fund decommissioning security through its balance sheet.
Appetite
The Group recognises that significant leverage was required to
fund its growth as low oil prices impacted revenues. However, it is
intent on further reducing its leverage levels, maintaining
liquidity, controlling costs and complying with its obligations to
finance providers while delivering shareholder value, recognising
that reasonable assumptions relating to external risks need to be
made in transacting with finance providers.
Mitigation
Debt reduction is a strategic priority. During 2021, the Group
refinanced its secured credit facility, enabling the acquisition of
the Golden Eagle area. Strong cash generation enabled the Group to
finance a larger portion of the Golden Eagle acquisition from cash
flow, resulting in a lower than expected drawdown on the Group's
RBL facility. At 23 March 2022, the RBL facility was drawn to $330
million, with voluntary early repayments ensuring the Group remains
ahead of the facility amortisation schedule.
Ongoing compliance with the financial covenants under the
Group's reserve based lending facility is actively monitored and
reviewed.
EnQuest generates operating cash inflow from the Group's
producing assets. The Group reviews its cash flow requirements on
an ongoing basis to ensure it has adequate resources for its
needs.
Where costs are incurred by external service providers, the
Group actively challenges operating costs. The Group also maintains
a framework of internal controls.
The Group continues to explore options to refinance its retail
and high yield bonds ahead of maturity in October 2023.
These steps, together with other mitigating actions available to
management, are expected to provide the Group with sufficient
liquidity to strengthen its balance sheet further.
Risk
Competition
The Group operates in a competitive environment across many
areas, including the acquisition of oil and gas assets, the
marketing of oil and gas, the procurement of oil and gas services
and access to human resources.
Potential impact
High (2020 High)
Likelihood
High (2020 High)
The potential impact and likelihood remain 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).
Appetite
The Group operates in a mature industry with well-established
competitors and aims to be the leading operator in the sector.
Mitigation
The Group has strong technical, commercial and business
development capabilities to ensure that it is well positioned to
identify and execute potential acquisition opportunities, utilising
innovative structures as may be appropriate.
The Group maintains good relations with oil and gas service
providers and constantly 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 Group achieves the
highest possible value for its production.
In addition, the marketing and trading group is responsible for
the Group's commodity price risk management activities in
accordance with the Group's business strategy.
Risk
IT security and resilience
The Group is exposed to risks arising from interruption to, or
failure of, IT infrastructure. The risks of disruption to normal
operations 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 or phishing exercises.
Potential impact
Medium (2020 Medium)
Likelihood
Medium (2020 Medium)
There has been no change to the potential impact or likelihood,
with the Group enhancing its IT security in light of the evolving
geopolitical situation.
Appetite
The Group endeavours to provide a secure IT environment that is
able to resist and withstand any attacks or unintentional
disruption that may compromise sensitive data, impact operations,
or destabilise its financial systems; it has a very low appetite
for this risk.
Mitigation
The Group has established IT capabilities and endeavours to be
in a position to defend its systems against disruption or
attack.
A number of tools to strengthen employee awareness continue to
be utilised, including videos, presentations, 'Yammer' posts and
poster campaigns.
The Safety, Climate and Risk Committee undertook additional
analyses of cyber--security risks in 2021. The Group has a
dedicated cyber--security manager and work on assessing the
cyber-security environment and implementing improvements as
necessary will continue during 2022.
Risk
Portfolio concentration
The Group's assets are primarily concentrated in the UK North
Sea around a limited number of infrastructure hubs 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 (2020 High)
Likelihood
High (2020 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.
During 2021, the Group acquired a 26.69% non-operated equity
interest in the Golden Eagle area, a 40.81% operating interest in
the Bressay heavy-oil field and 100.00% equity interest in the
P1078 licence in the UK North Sea containing the proven Bentley
heavy-oil discovery.
The Group continues to assess acquisition growth opportunities
with a view to improving its asset diversity over time.
The Group also established an Infrastructure and New Energy
business to unlock renewable energy and decarbonisation
opportunities in the medium to long term.
Appetite
Although the extent of portfolio concentration is moderated by
production generated in Malaysia, the majority of the Group's
assets remain relatively concentrated in the UK North Sea and
therefore this risk remains intrinsic to the Group.
Mitigation
This risk is mitigated in part through acquisitions. For all
acquisitions, the Group uses a number of business development
resources, both in the UK and internationally, to liaise with
vendors/governments and evaluate and transact acquisitions. This
includes performing extensive due diligence (using in-house and
external personnel) and actively involving executive management in
reviewing commercial, technical and other business risks together
with mitigation measures.
The Group also constantly keeps its portfolio under rigorous
review and, accordingly, actively considers the potential for
making disposals and divesting, executing development projects,
making international acquisitions, expanding hubs and potentially
investing in gas assets, export capability or renewable energy and
decarbonisation projects where such opportunities are consistent
with the Group's focus on enhancing net revenues, generating cash
flow and strengthening the balance sheet.
Risk
Subsurface risk and reserves replacement
Failure to develop its contingent and prospective resources or
secure new licences and/or asset acquisitions and realise their
expected value.
Potential impact
High (2020 High)
Likelihood
Medium (2020 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.
Appetite
Reserves replacement is an element of the sustainability of the
Group and its ability to grow. The Group has some tolerance for the
assumption of risk in relation to the key activities required to
deliver reserves growth, such as drilling and acquisitions.
Mitigation
The Group puts a strong emphasis on subsurface analysis and
employs industry--leading professionals. 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,
Golden Eagle and PM8/Seligi that it believes can primarily be
accessed through low-cost subsea drilling and tie-backs to existing
infrastructure. EnQuest continues to evaluate the substantial 2C
resources at Bressay, Bentley and PM409 to identify future drilling
prospects. Bressay and Bentley are located close to the Group's
Kraken development, while PM409 is contiguous to the Group's
existing PM8/Seligi PSC, providing low-cost tie-back
opportunities.
The Group continues to consider potential opportunities to
acquire new production resources that meet its investment
criteria.
Risk
Project execution and delivery
The Group's success will be partially dependent upon the
successful execution and delivery of potential future projects,
including decommissioning and Infrastructure and New Energy
opportunities in the UK, that are undertaken.
Potential impact
Medium (2020 Medium)
Likelihood
Low (2020 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 and Infrastructure and New Energy projects over an
extended period of time.
Appetite
The efficient delivery of projects has been a key feature of the
Group's long--term strategy. The Group's appetite is to identify
and implement short--cycle development projects such as infill
drilling and near-field tie-backs in its Upstream business,
industrialise decommissioning projects to ensure cost efficiency
and unlock new energy and decarbonisation opportunities through
innovative commercial structures. While the Group necessarily
assumes significant risk when it sanctions a new project (for
example, by incurring costs against oil price assumptions), or a
decommissioning programme, it requires that risks to efficient
project delivery are minimised.
Mitigation
The Group has teams which are responsible for the planning and
execution of new projects with a dedicated team for each project.
The Group has detailed controls, systems and monitoring processes
in place, notably the Capital Projects Delivery Process, to ensure
that deadlines are met, costs are controlled and that design
concepts and the Field Development Plan are adhered to and
implemented. These 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 to
deliver projects safely at the lowest possible cost and associated
emissions.
In Infrastructure and New Energy, the Group intends to work with
experienced third-party organisations and utilise innovative
commercial structures to develop new energy and decarbonisation
opportunities.
The Group also engages third--party assurance experts to review,
challenge and, where appropriate, make recommendations to improve
the processes for project management, cost control and governance
of major projects. EnQuest ensures that responsibility for
delivering time-critical supplier obligations and lead times are
fully understood, acknowledged and proactively managed by the most
senior levels within supplier organisations.
Risk
Fiscal risk and government take
Unanticipated changes in the regulatory or fiscal environment
can affect the Group's ability to deliver its strategy/business
plan and potentially impact revenue and future developments.
Potential impact
High (2020 High)
Likelihood
Medium (2020 Medium)
There has been no material change in the potential impact or
likelihood, although the exit of the UK from the European Union has
impacted the regulatory environment going forward, for example by
affecting the cost of emissions trading certificates through the
smaller UK emissions trading scheme.
Appetite
The Group faces an uncertain macroeconomic and regulatory
environment.
Due to the nature of such risks and their relative
unpredictability, it must be tolerant of certain inherent
exposure.
Mitigation
It is difficult for the Group to predict the timing or severity
of such changes. However, through Offshore Energies UK and other
industry associations, the Group engages with government and other
appropriate organisations in order to keep abreast of expected and
potential changes; the Group also takes an active role in making
appropriate representations.
All business development or investment activities recognise
potential tax implications and the Group maintains relevant
internal tax expertise.
At an operational level, the Group has procedures to identify
impending changes in relevant regulations to ensure legislative
compliance.
Risk
International business
While the majority of the Group's activities and assets are in
the UK, the international business is still material. The Group's
international business is subject to the same risks as the UK
business (e.g. 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 (2020 Medium)
Likelihood
Medium (2020 Medium)
There has been no material change in the impact or
likelihood.
Appetite
In light of its long-term growth strategy, the Group seeks to
expand and diversify its production (geographically and in terms of
quantum); as such, it is tolerant of assuming certain commercial
risks which may accompany the opportunities it pursues.
However, such tolerance does not impair the Group's commitment
to comply with legislative and regulatory requirements in the
jurisdictions in which it operates. Opportunities should enhance
net revenues and facilitate strengthening of the balance sheet.
Mitigation
Prior to entering a new country, EnQuest evaluates the host
country to assess whether there is an adequate and established
legal and political framework in place to protect and safeguard
first its expatriate and local staff and, second, any investment
within the country in question.
When evaluating international business risks, executive
management reviews commercial, technical, ethical and other
business risks, together with mitigation and how risks can be
managed by the business on an ongoing basis.
EnQuest looks to employ 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.
Where appropriate, the risks may be mitigated by entering into a
joint venture with partners with local knowledge and
experience.
After country entry, EnQuest maintains a dialogue with local and
regional government, particularly with those responsible for oil,
energy and fiscal matters, and may obtain support from appropriate
risk consultancies. When there is a significant change in the risk
to people or assets within a country, the Group takes appropriate
action to safeguard people and assets.
Risk
Joint venture partners
Failure by joint venture parties to fund their obligations.
Dependence on other parties where the Group is non-operator.
Potential impact
Medium (2020 Medium)
Likelihood
Low (2020 Low)
There has been no material change in the potential impact or
likelihood.
Appetite
The Group requires partners of high integrity. It recognises
that it must accept a degree of exposure to the creditworthiness of
partners and evaluates this aspect carefully as part of every
investment decision.
Mitigation
The Group operates regular cash call and billing arrangements
with its co-venturers to mitigate the Group's credit exposure at
any one point in time and keeps in regular dialogue with each of
these parties to ensure payment. Risk of default is mitigated by
joint operating agreements 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.
The Group generally prefers to be the operator. The Group
maintains regular dialogue with its partners to ensure alignment of
interests and to maximise the value of joint venture assets, taking
account of the impact of any wider developments.
Risk
Reputation
The reputational and commercial exposures 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 (2020 High)
Likelihood
Low (2020 Low)
There has been no material change in the potential impact or
likelihood.
Appetite
The Group has no tolerance for conduct which may compromise its
reputation for integrity and competence.
Mitigation
All activities are conducted in accordance with approved
policies, standards and procedures. Interface agreements are agreed
with all core contractors.
The Group requires adherence to its Code of Conduct and runs
compliance programmes to provide assurance on conformity with
relevant legal and ethical requirements.
The Group undertakes regular audit activities 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.
All personnel are authorised to shut down production for
safety-related reasons. As an example, the Group acted promptly in
temporarily shutting down the Magnus platform when it was clear its
flaring consent would be breached.
The Group has a clear ESG strategy, with a focus on health and
safety (including asset integrity), emissions reductions, looking
after its employees, positively impacting the communities in which
the Group operates, upholding a robust RMF and acting with high
standards of integrity. The Group is successfully implementing this
strategy.
Risk
Human resources
The Group's success continues to be dependent upon its ability
to attract and retain key personnel and develop organisational
capability 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 (2020 Medium)
Likelihood
Medium (2020 Medium)
There has been no material change to potential impact or
likelihood.
Appetite
As a low-cost, lean organisation, the Group relies on motivated
and high--quality employees to achieve its targets and manage its
risks.
The Group recognises that the benefits of a lean, flexible and
diverse organisation requires creativity and agility to protect
against the risk of skills shortages.
Mitigation
The Group has established an able and competent employee base to
execute its principal activities. In addition, the Group seeks to
maintain good relationships with its employees and contractor
companies and regularly monitors the employment market to provide
remuneration packages, bonus plans and long-term share-based
incentive plans that incentivise performance and long-term
commitment from employees to the Group.
The Group recognises that its people are critical to its success
and so is continually evolving EnQuest's end--to--end people
management processes, including recruitment and selection, career
development and performance management. This ensures that EnQuest
has the right person for the job and that appropriate training,
support and development opportunities are provided, with feedback
collated to drive continuous improvement whilst delivering SAFE
Results. The culture of the Group is an area of ongoing focus and
employee surveys and forums have been undertaken to understand
employees' views on key areas, including diversity and inclusion,
in order to develop appropriate action plans.
EnQuest is considering the appropriate balance for its onshore
teams between site, office and home working to promote strong
productivity and business performance facilitated by an engaged
workforce. The Group also maintains market--competitive contracts
with key suppliers to support the execution of work where the
necessary skills do not exist within the Group's employee base.
The Group recognises that there is a gender pay gap within the
organisation but that there is no issue with equal pay for the same
tasks. EnQuest also recognises that fewer young people may join the
industry due to climate change-related factors. EnQuest aims to
attract the best talent, recognising the value and importance of
diversity.
To ensure improved diversity in the Group's leadership, various
targets have been implemented during 2021.
Executive and senior management retention, succession planning
and development remain important priorities for the Board. It is a
Board--level priority that executive and senior management possess
the appropriate mix of skills and experience to realise the Group's
strategy.
Following its introduction in 2019, the Group's global employee
forum has continued to add to EnQuest's employee communication and
engagement strategy, improving interaction between the workforce
and the Board.
The Group continues to monitor the evolving situation with
regard to the impacts of COVID-19 in conjunction with a variety of
stakeholders, including industry and medical organisations.
Appropriate actions will continue to be implemented in accordance
with expert advice and the prevailing level of risk.
KEY PERFORMANCE INDICATORS
2021 2020 2019
--------------------------------------------- -------- -------- --------
ESG metrics:
Group LTIF(1) 0.21 0.22 0.57
Emissions (kilo-tonnes of CO(2) equivalent) 1,145.3 1,342.8 1,511.6
--------------------------------------------- -------- -------- --------
Business performance data:
Production (Boepd) 44,415 59,116 68,606
Unit opex (production and transportation
costs) ($/Boe)(2) 20.5 15.2 20.6
Cash expenditures ($ million) 117.6 173.0 248.6
Capital(2) 51.8 131.4 237.5
Abandonment 65.8 41.6 11.1
--------------------------------------------- -------- -------- --------
Reported data:
Cash generated from operations ($ million) 756.9 567.2 993.4
Net debt including PIK ($ million)(2) 1,222.0 1,279.7 1,413.0
Net 2P reserves (MMboe) 194 189 213
--------------------------------------------- -------- -------- --------
(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 66
OIL AND GAS RESERVES AND RESOURCES
EnQuest oil and gas reserves and resources
UKCS(12) Other regions(12) Total(12)
------------ ------------------- ---------
MMboe MMboe MMboe MMboe MMboe
--------------------------------------- ----- ----- --------- -------- ---------
Proven and probable reserves(1,
2, 3 and 4)
----- ----- --------- -------- ---------
At 31 December 2020 166 22 189
----- ----- --------- -------- ---------
Acquisitions and dispoals(5) 19 - 19
----- ----- --------- -------- ---------
Revisions of previous estimates - (1) (1)
----- ----- --------- -------- ---------
Transfers from contingent resources(6) 3 1 4
----- ----- --------- -------- ---------
22 (0) 22
----- ----- --------- -------- ---------
Production:
----- ----- --------- -------- ---------
Export meter (14) (2) (16)
----- ----- --------- -------- ---------
Volume adjustments(7) 0 -
----- ----- --------- -------- ---------
(14) (2) (16)
--------------------------------------- ----- ----- --------- -------- ---------
Total proven and probable reserves
at 31 December 2021(8) 174 20 194
--------------------------------------- ----- ----- --------- -------- ---------
Contingent resources(1, 2 and 9)
----- ----- --------- -------- ---------
At 31 December 2020 77 87 164
----- ----- --------- -------- ---------
Acquisitions and dispoals(10) 249 - 249
----- ----- --------- -------- ---------
Revisions of previous estimates (6) (1) (7)
----- ----- --------- -------- ---------
Promoted to reserves(11) (3) (1) (4)
--------------------------------------- ----- ----- --------- -------- ---------
Total contingent resources at 31
December 2021 316 86 402
--------------------------------------- ----- ----- --------- -------- ---------
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 Acquisition of 26.69% non-operated interest in Golden
Eagle
6 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 volumes that
will be consumed as fuel gas; including c.7 MMboe at Magnus, c.1
MMboe at Kraken and c.1 MMboe at Golden Eagle
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 Acquisition of 40.81% interest in Bressay, 100.00% interest
in Bentley and 26.69% non-operated interest in Golden Eagle
11 Kraken, Magnus and PM8/Seligi opportunity maturation
12 Rounding may apply
Group Income Statement
For the year ended 31 December 2021
2021 2020 restated(i)
------------------------- ----- ----------------------------------------- -----------------------------------------
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) 1,320,265 (54,451) 1,265,814 855,074 8,778 863,852
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Cost of sales 5(b) (900,433) (7,201) (907,634) (785,455) (13,626) (799,081)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Gross profit/(loss) 419,832 (61,652) 358,180 69,619 (4,848) 64,771
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Net impairment
reversal/(charge)
to oil and gas assets 4 - 39,715 39,715 - (422,495) (422,495)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
General and
administration
expenses 5(c) (363) - (363) (6,105) - (6,105)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Other income 5(d) 30,990 162,647 193,637 18,100 138,249 156,349
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Other expenses 5(e) (7,278) (3,832) (11,110) (101,633) (956) (102,589)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Profit/(loss) from
operations
before tax and finance
income/(costs) 443,181 136,878 580,059 (20,019) (290,050) (310,069)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Finance costs 6 (169,451) (58,395) (227,846) (179,818) (77,259) (257,077)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Finance income 6 228 - 228 1,171 - 1,171
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Profit/(loss) before tax 273,958 78,483 352,441 (198,666) (367,309) (565,975)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Income tax 7 (53,674) 78,221 24,547 172,479 (76,449) 96,030
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Profit/(loss) for the
year
attributable to owners
of the parent 220,284 156,704 376,988 (26,187) (443,758) (469,945)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
Total comprehensive
profit/(loss)
for the year,
attributable
to owners of the parent 376,988 (469,945)
------------------------- ----- ------------ ---------------- --------- ------------ ---------------- ---------
(i) The comparative information has been restated as a result of
change in accounting policy and prior period error. For more
information, see note 2 Basis of preparation - Restatements
There is no comprehensive income attributable to the
shareholders of the Group other than the profit for the period.
Revenue and operating (loss)/profit are all derived from continuing
operations.
Earnings per share 8 $ $ $ $
------------------- ------ ----- -------- -------
Basic 0.127 0.217 (0.016) (0.290)
------------------- ------ ----- -------- -------
Diluted 0.125 0.214 (0.016) (0.290)
------------------- ------ ----- -------- -------
The attached notes 1 to 29 form part of these Group financial
statements.
Group Balance Sheet
At 31 December 2021
2021 2020 restated(i)
Notes $'000 $'000
------------------------------ ----- --------- ----------------
ASSETS
------------------------------ ----- --------- ----------------
Non-current assets
------------------------------ ----- --------- ----------------
Property, plant and equipment 10 2,821,998 2,633,917
------------------------------ ----- --------- ----------------
Goodwill 11 134,400 134,400
------------------------------ ----- --------- ----------------
Intangible assets 12 47,667 27,546
------------------------------ ----- --------- ----------------
Deferred tax assets 7(c) 702,970 659,803
------------------------------ ----- --------- ----------------
Other financial assets 19 6 7
------------------------------ ----- --------- ----------------
3,707,041 3,455,673
------------------------------ ----- --------- ----------------
Current assets
------------------------------ ----- --------- ----------------
Inventories 13 73,023 59,784
------------------------------ ----- --------- ----------------
Trade and other receivables 16 296,068 118,715
------------------------------ ----- --------- ----------------
Current tax receivable 2,368 5,601
------------------------------ ----- --------- ----------------
Cash and cash equivalents 14 286,661 222,830
------------------------------ ----- --------- ----------------
Other financial assets 19 472 -
------------------------------ ----- --------- ----------------
658,592 406,930
------------------------------ ----- --------- ----------------
TOTAL ASSETS 4,365,633 3,862,603
------------------------------ ----- --------- ----------------
EQUITY AND LIABILITIES
------------------------------ ----- --------- ----------------
Equity
------------------------------ ----- --------- ----------------
Share capital and premium 20 392,196 345,420
------------------------------ ----- --------- ----------------
Share-based payment reserve 6,791 1,016
------------------------------ ----- --------- ----------------
Retained earnings 20 121,769 (255,219)
------------------------------ ----- --------- ----------------
TOTAL EQUITY 520,756 91,217
------------------------------ ----- --------- ----------------
Non-current liabilities
------------------------------ ----- --------- ----------------
Borrowings 18 191,109 37,854
------------------------------ ----- --------- ----------------
Bonds 18 1,081,596 1,045,041
------------------------------ ----- --------- ----------------
Leases liabilities 24 442,500 548,407
------------------------------ ----- --------- ----------------
Contingent consideration 22 380,301 448,384
------------------------------ ----- --------- ----------------
Provisions 23 754,266 741,453
------------------------------ ----- --------- ----------------
Deferred tax liabilities 7(c) 3,418 6,385
------------------------------ ----- --------- ----------------
2,853,190 2,827,524
------------------------------ ----- --------- ----------------
Current liabilities
------------------------------ ----- --------- ----------------
Borrowings 18 210,505 414,430
------------------------------ ----- --------- ----------------
Leases liabilities 24 128,281 99,439
------------------------------ ----- --------- ----------------
Contingent consideration 22 30,477 73,877
------------------------------ ----- --------- ----------------
Provisions 23 140,676 98,954
------------------------------ ----- --------- ----------------
Trade and other payables 17 420,544 255,155
------------------------------ ----- --------- ----------------
Other financial liabilities 19 55,247 2,007
------------------------------ ----- --------- ----------------
Current tax payable 5,957 -
------------------------------ ----- --------- ----------------
991,687 943,862
------------------------------ ----- --------- ----------------
TOTAL LIABILITIES 3,844,877 3,771,386
------------------------------ ----- --------- ----------------
TOTAL EQUITY AND LIABILITIES 4,365,633 3,862,603
------------------------------ ----- --------- ----------------
(i) The comparative information has been restated as a result of
change in accounting policy and prior period error. For more
information, see note 2 Basis of preparation - Restatements
The attached notes 1 to 29 form part of these Group financial
statements.
The financial statements were approved by the Board of Directors
and authorised for issue on 23 March 2022 and signed on its behalf
by:
Jonathan Swinney
Chief Financial Officer
Group Statement of Changes in Equity
For the year ended 31 December 2021
Merger
Share
capital Share-based
and share payments Retained
premium Reserve(i) reserve earnings Total
$'000 $'000 $'000 $'000 $'000
------------------------------------------- ---------- ----------- ----------- --------- ---------
Balance at 1 January 2020 345,420 662,855 (1,085) (448,129) 559,061
------------------------------------------- ---------- ----------- ----------- --------- ---------
Profit/(loss) for the year (restated)(ii) - - - (469,945) (469,945)
------------------------------------------- ---------- ----------- ----------- --------- ---------
Total comprehensive loss for the year
(restated)(ii) - - - (469,945) (469,945)
------------------------------------------- ---------- ----------- ----------- --------- ---------
Share-based payment (see note 21) - - 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 (restated)(ii) 345,420 - 1,016 (255,219) 91,217
------------------------------------------- ---------- ----------- ----------- --------- ---------
Profit/(loss) for the year - - - 376,988 376,988
------------------------------------------- ---------- ----------- ----------- --------- ---------
Total comprehensive profit for the year - - - 376,988 376,988
------------------------------------------- ---------- ----------- ----------- --------- ---------
Issue of share capital, net of expenses 46,200 - - - 46,200
------------------------------------------- ---------- ----------- ----------- --------- ---------
Share-based payment (see note 21) - - 6,351 - 6,351
------------------------------------------- ---------- ----------- ----------- --------- ---------
Shares purchased on behalf of Employee
Benefit Trust 576 - (576) - -
------------------------------------------- ---------- ----------- ----------- --------- ---------
Balance at 31 December 2021 392,196 - 6,791 121,769 520,756
------------------------------------------- ---------- ----------- ----------- --------- ---------
(i) In 2020, the merger reserve was released to retained
earnings as the assets which gave rise to its original recognition
were fully written down
(ii) The comparative information has been restated as a result
of change in accounting policy and prior period error. For more
information, see note 2 Basis of preparation - Restatements
The attached notes 1 to 29 form part of these Group financial
statements.
Group Statement of Cash Flows
For the year ended 31 December 2021
2020
2021 restated(i)
Notes $'000 $'000
------------------------------------------------------- ----- --------- ------------
CASH FLOW FROM OPERATING ACTIVITIES
------------------------------------------------------- ----- --------- ------------
Cash generated from operations 29 756,928 567,165
------------------------------------------------------- ----- --------- ------------
Cash received from insurance 674 -
------------------------------------------------------- ----- --------- ------------
Cash received/(paid) on sale/(purchase) of financial
instruments (277) 6,226
------------------------------------------------------- ----- --------- ------------
Decommissioning spend (65,791) (41,605)
------------------------------------------------------- ----- --------- ------------
Income taxes paid (17,396) (10,366)
------------------------------------------------------- ----- --------- ------------
Net cash flows from/(used in) operating activities 674,138 521,420
------------------------------------------------------- ----- --------- ------------
INVESTING ACTIVITIES
------------------------------------------------------- ----- --------- ------------
Purchase of property, plant and equipment (43,712) (131,376)
------------------------------------------------------- ----- --------- ------------
Purchase of intangible oil and gas assets (8,127) -
------------------------------------------------------- ----- --------- ------------
Purchase of other intangible assets 12 (10,052) -
------------------------------------------------------- ----- --------- ------------
Net cash received on termination of Tanjong Baram risk
service contract - 51,054
------------------------------------------------------- ----- --------- ------------
Repayment of Magnus contingent consideration - Profit
share 22 (968) (41,071)
------------------------------------------------------- ----- --------- ------------
Acquisitions (258,627) -
------------------------------------------------------- ----- --------- ------------
Interest received 256 796
------------------------------------------------------- ----- --------- ------------
Net cash flows (used in)/from investing activities (321,230) (120,597)
------------------------------------------------------- ----- --------- ------------
FINANCING ACTIVITIES
------------------------------------------------------- ----- --------- ------------
Net proceeds of share issue 47,782 -
------------------------------------------------------- ----- --------- ------------
Proceeds of loans and borrowings 125,000 -
------------------------------------------------------- ----- --------- ------------
Repayment of loans and borrowings (184,276) (210,671)
------------------------------------------------------- ----- --------- ------------
Repayment of Magnus contingent consideration - Vendor
loan 22 (73,728) (20,702)
------------------------------------------------------- ----- --------- ------------
Shares purchased by Employee Benefit Trust (576) (1,153)
------------------------------------------------------- ----- --------- ------------
Repayment of obligations under financing leases 24 (136,651) (123,001)
------------------------------------------------------- ----- --------- ------------
Interest paid (63,025) (42,961)
------------------------------------------------------- ----- --------- ------------
Other finance costs paid - (2,526)
------------------------------------------------------- ----- --------- ------------
Net cash flows from/(used in) financing activities (285,474) (401,014)
------------------------------------------------------- ----- --------- ------------
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS 67,434 (191)
------------------------------------------------------- ----- --------- ------------
Net foreign exchange on cash and cash equivalents (3,603) 2,566
------------------------------------------------------- ----- --------- ------------
Cash and cash equivalents at 1 January 222,830 220,455
------------------------------------------------------- ----- --------- ------------
CASH AND CASH EQUIVALENTS AT 31 DECEMBER 286,661 222,830
------------------------------------------------------- ----- --------- ------------
Reconciliation of cash and cash equivalents
------------------------------------------------------- ----- --------- ------------
Total cash at bank and in hand 14 276,970 221,155
------------------------------------------------------- ----- --------- ------------
Restricted cash 14 9,691 1,675
------------------------------------------------------- ----- --------- ------------
Cash and cash equivalents per balance sheet 286,661 222,830
------------------------------------------------------- ----- --------- ------------
(i) The comparative information has been restated as a result of
change in accounting policy and prior period error. For more
information, see note 2 Basis of preparation - Restatements
The attached notes 1 to 29 form part of these Group financial
statements.
Notes to the Group Financial Statements
For the year ended 31 December 2021
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
address of the Company's registered office is 5(th) Floor, Cunard
House, 15 Regent Street, London, SW1Y 4LR.
The principal activities of the Company and its subsidiaries
(together the 'Group') are to responsibly optimise production,
leverage existing infrastructure, deliver a strong decommissioning
performance and explore new energy and further decarbonisation
opportunities.
The Group's financial statements for the year ended 31 December
2021 were authorised for issue in accordance with a resolution of
the Board of Directors on 23 March 2022.
A listing of the Group's companies is contained in note 28 to
these Group financial statements.
2. Basis of preparation
The consolidated financial statements have been prepared in
accordance with UK-adopted International Accounting Standards and
International Financial Reporting Standards as issued by the IASB
and in conformity with the requirements of the Companies Act 2006.
The accounting policies which follow set out those policies which
apply in preparing the financial statements for the year ended 31
December 2021.
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 its
Business performance results and its 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 separately in order to enable
shareholders to understand better and evaluate the Group's reported
financial performance. For further information see note 4.
Restatements
Presentation of rental income
EnQuest receives rental income for sub-leasing space in its
corporate offices. The Group previously presented the rental income
associated with office sub-leases within revenue and other
operating income in the income statement. The Group has determined
that the revenue derived from this income is not related to the
principal activities of the Group and should be presented within
other income in the income statement. Comparative information has
been restated, resulting in a $1.8 million reduction in revenue and
other operating income and a $1.8 million increase in other income.
There is no impact on comparative information for profit/(loss)
from operations before tax and finance income/(costs) or earnings
per share.
Presentation of Group Statement of Cash Flows
Following a review of the Group's primary statements, the Group
has updated the presentation of the Group Statement of Cash Flows
to reconcile to cash and cash equivalents per the balance sheet. In
previous years, the Group Statement of Cash Flows was reconciled to
cash and cash equivalents excluding restricted cash. Following this
change, the presentation of the Group Statement of Cash Flows in
2020 has been restated, which has resulted in a $0.7 million
reduction in cash flows from operating activities.
Deferred tax asset restatement
Subsequent to the publication of the Group's 2020 consolidated
financial statements and as part of the preparation of its interim
report, the Group determined there was an inconsistency in the
calculation of the deferred tax asset recognised on the balance
sheet associated with Magnus contingent consideration and the
relevant estimated future cash flows used in the calculation of
future taxable profits to support the recognition of this deferred
tax asset and the deferred tax asset associated with other
available tax losses. This inconsistency resulted in excess
deferred tax being derecognised within Remeasurements and
exceptional items of $155.9 million with respect to the year ended
31 December 2020. There are no changes to the underlying amounts
recognised in relation to contingent consideration or to amounts
recognised in respect of deferred tax in earlier periods. The
tables below reflect the corrections to the comparative periods
which are disclosed in these Group financial statements.
Group Income Statement(i)
Restatement
2020 (as previously reported) adjustment 2020 restated
------------------ ---------------------------------------- -------------- --------------------------------------
Remeasurements Remeasurements
and and
exceptional Reported exceptional
Business items (note in Business items (note Reported
performance 4) period performance 4) in period
$'000 $'000 $'000 $'000 $'000 $'000 $'000
------------------ ------------ -------------- --------- ----------- -------------- -------------- ----------
Profit/(loss)
before
tax (198,666) (367,309) (565,975) (198,666) (367,309) (565,975)
------------------ ------------ -------------- --------- ----------- -------------- -------------- ----------
Income tax 172,479 (232,306) (59,827) 155,857 172,479 (76,449) 96,030
------------------ ------------ -------------- --------- ----------- -------------- -------------- ----------
Profit/(loss) for
the year
attributable
to owners of the
parent (26,187) (599,615) (625,802) 155,857 (26,187) (443,758) (469,945)
------------------ ------------ -------------- --------- ----------- -------------- -------------- ----------
Total
comprehensive
profit/(loss) for
the period,
attributable
to owners of the
parent (625,802) 155,857 (469,945)
------------------ ------------ -------------- --------- ----------- -------------- -------------- ----------
Earnings per
share $ $ $ $
------------- -------- ------- ----- -------- -------
Basic (0.016) (0.378) 0.088 (0.016) (0.290)
------------- -------- ------- ----- -------- -------
Diluted (0.016) (0.378) 0.088 (0.016) (0.290)
------------- -------- ------- ----- -------- -------
(i) Only the impact of the material deferred tax asset
restatement presented
Group Balance Sheet (i)
2020 (as
previously Restatement
reported) adjustment
2020 restated
$'000 $'000 $'000
ASSETS
----------------------------- ----------- ----------- -------------
Non-current assets
----------------------------- ----------- ----------- -------------
Deferred tax assets 503,946 155,857 659,803
----------------------------- ----------- ----------- -------------
TOTAL ASSETS 3,706,746 155,857 3,862,603
----------------------------- ----------- ----------- -------------
EQUITY AND LIABILITIES
----------------------------- ----------- ----------- -------------
Equity
----------------------------- ----------- ----------- -------------
Retained earnings (411,076) 155,857 (255,219)
----------------------------- ----------- ----------- -------------
TOTAL EQUITY (64,640) 155,857 91,217
----------------------------- ----------- ----------- -------------
TOTAL EQUITY AND LIABILITIES 3,706,746 155,857 3,862,603
----------------------------- ----------- ----------- -------------
(i) Only the impact of the material deferred tax asset
restatement presented
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.
The health, safety and wellbeing of the Group's employees is its
top priority and it continues to monitor actively the impact on
operations from COVID-19. 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 is cognisant of the ongoing risks presented by the
evolving situation. 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.
During 2021, the Group signed a new senior secured borrowing
base debt facility (the 'RBL') of $600.0 million and an additional
amount of $150.0 million for letters of credit for up to seven
years, subject to refinancing the Group's existing high yield
bonds. The RBL is initially repaid based on an amortisation
schedule and via a cash sweep mechanism, whereby any unrestricted
cash in excess of $75.0 million is swept to repay outstanding
amounts at calendar quarter ends. Application of the amortisation
schedule ensures the RBL is fully repaid by June 2023.
Upon refinancing of the Group's High Yield Bond, the maturity of
the RBL is extended to seven years from its signing date (11 June
2021), or the point at which the remaining economic reserves for
all borrowing base assets are projected to fall below 25% of the
initial economic reserves forecast, if earlier.
At 31 December 2021, $415.0 million was drawn on the RBL, with
early voluntary repayments of $85.0 million made in the first
quarter of 2022.
The Group continues to explore options to refinance its Retail
and High Yield Bonds ahead of maturity in October 2023. For the
purposes of assessing going concern it is assumed that the
refinancing of the bonds occurs outside of the going concern
period. However, in the scenario that the Group concluded a
successful refinancing of the bonds within the next 12 months, then
the going concern basis at the date of release of this annual
report would also be considered appropriate.
The Group's latest approved business plan underpins management's
base case ('Base Case') and is in line with the Group's production
guidance and uses oil price assumptions of $75.0/bbl for 2022 and
$70.0/bbl for 2023, adjusted for hedging activity undertaken.
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 $67.5/bbl for 2022 and $63.0/bbl for 2023;
-- Production risking of c.5% for 2022 and 2023; and
-- 2.5% increase in operating costs.
The Base Case and Downside Case indicate that the Group is able
to operate as a going concern and remain covenant compliant 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 liquidity breakeven price in the going concern
period being less than $60.0/bbl in order to maintain a minimum
unrestricted cash balance of above $50.0 million across all periods
(as required by the RBL).
Should circumstances arise that differ from the Group's
projections, the Directors believe that a number of mitigating
actions, including 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.
After making appropriate 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 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:
-- Interest Rate Benchmark Reform - Phase 2 (Amendments to IFRS
9, IAS 39, IFRS 7, IFRS 4 and IFRS 16)
-- COVID-19-Related Rent Concessions beyond 30 June 2021 (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 IAS 8 and Disclosure of Accounting Policies
Disclosure of Accounting Policies
------------------------------- ---------------------------------------------------------
Amendments to IFRS 3 Reference to the Conceptual Framework
Amendments to IAS 12 Deferred Tax related to Assets and Liabilities
arising from a Single Transaction
------------------------------- ---------------------------------------------------------
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.
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 recognises its
share of assets, liabilities, income and expenses of the joint
operation in the consolidated financial statements on a
line-by-line basis. During 2021, 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 Group 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.
Emissions liabilities
The Group operates in an energy intensive industry and is
therefore required to partake in emission trading schemes ('ETS')
(2021: UK ETS, 2020: EU ETS). The Group recognises an emission
liability in line with the production of emissions that give rise
to the obligation. To the extent the liability is covered by
allowances held, the liability is recognised at the cost of these
allowances held and if insufficient allowances are held, the
remaining uncovered portion is measured at the spot market price of
allowances at the balance sheet date. The expense is presented
within 'production costs' under 'cost of sales' and the accrual is
presented in 'trade and other payables'. Any allowance purchased to
settle the Group's liability is recognised on the balance sheet as
an intangible asset. Both the emission allowances and the emission
liability are derecognised upon settling the liability with the
respective regulator.
Use of judgements, estimates and assumptions
The preparation of the Group's consolidated financial statements
requires management to make judgements, estimates and assumptions
that affect the reported amounts of revenues, expenses, assets and
liabilities, and the accompanying disclosures, at the date of the
consolidated financial statements. Estimates and assumptions are
continuously evaluated and are based on management's experience and
other factors, including expectations of future events that are
believed to be reasonable under the circumstances. Uncertainty
about these assumptions and estimates could result in outcomes that
require a material adjustment to the carrying amount of assets or
liabilities affected in future periods.
The accounting judgements and estimates that have a significant
impact on the results of the Group are set out below and should be
read in conjunction with the information provided in the Notes to
the financial statements. Judgements and estimates, not all of
which are significant, made in assessing the impact of climate
change and the transition to a lower carbon economy on the
consolidated financial statements are also set out below. Where an
estimate has a significant risk of resulting in a material
adjustment to the carrying amounts of assets and liabilities within
the next financial year, this is specifically noted.
Climate change and energy transition
As covered in our principal risks on oil and gas prices on page
19, the Group recognises that the energy transition is likely to
impact the demand, and hence the future prices, of commodities such
as oil and natural gas. This in turn may affect the recoverable
amount of property, plant and equipment, and goodwill in the oil
and gas industry. The Group acknowledges that there are a range of
possible energy transition scenarios that may indicate different
outcomes for oil prices. There are inherent limitations with
scenario analysis and it is difficult to predict which, if any, of
the scenarios might eventuate.
The Group has assessed the potential impacts of climate change
and the transition to a lower carbon economy in preparing the
consolidated financial statements, including the Group's current
assumptions relating to demand for oil and natural gas and their
impact on the Group's long-term price assumptions. See
Recoverability of asset carrying values: Oil prices.
While the pace of transition to a lower carbon economy is
uncertain, oil and natural gas demand is expected to remain a key
element of the energy mix for many years based on stated policies,
commitments and announced pledges to reduce emissions. Therefore,
given the useful lives of the Group's current portfolio of oil and
gas assets, a material adverse change is not expected to the
carrying values of EnQuest's assets and liabilities as a result of
climate change and the transition to a lower carbon economy.
Management will continue to review price assumptions as the
energy transition progresses and this may result in impairment
charges or reversals in the future.
Critical accounting judgements and key sources of estimation
uncertainty
The Group has considered its critical accounting judgements and
key sources of estimation uncertainty, and these are set out
below.
Recoverability of asset carrying values
Judgements: The Group assesses each asset or cash-generating
unit ('CGU') (excluding goodwill, which is assessed annually
regardless of indicators) in each reporting period to determine
whether any indication of impairment exists. Assessment of
indicators of impairment or impairment reversal and the
determination of the appropriate grouping of assets into a CGU or
the appropriate grouping of CGUs for impairment purposes require
significant management judgement. For example, individual oil and
gas properties may form separate CGUs whilst certain oil and gas
properties with shared infrastructure may be grouped together to
form a single CGU. Alternative groupings of assets or CGUs may
result in a different outcome from impairment testing. See note 11
for details on how these groupings have been determined in relation
to the impairment testing of goodwill.
Estimates: Where an indicator of impairment exists, a formal
estimate of the recoverable amount is made, which is considered to
be the higher of the fair value less costs to dispose ('FVLCD') and
value in use ('VIU'). The assessments require the use of estimates
and assumptions such as the effects of inflation and deflation on
operating expenses, discount rates, capital expenditure, production
profiles, reserves and resources, and future commodity prices,
including the outlook for global or regional market
supply-and-demand conditions for crude oil and natural gas.
As described above, the recoverable amount of an asset is the
higher of its VIU and its FVLCD. When the recoverable amount is
measured by reference to FVLCD, in the absence of quoted market
prices or binding sale agreement, estimates are made regarding the
present value of future post-tax cash flows. These estimates are
made from the perspective of a market participant and include
prices, future production volumes, operating costs, capital
expenditure, decommissioning costs, tax attributes, risking factors
applied to cash flows and discount rates. Reserves and resources
are included in the assessment of FVLCD to the extent that it is
considered probable that a market participant would attribute value
to them.
Details of impairment charges and reversals recognised in the
income statement and details on the carrying amounts of assets are
shown in note 10, note 11 and note 12.
The estimates for assumptions made in impairment tests in 2021
relating to discount rates and oil prices are discussed below.
Changes in the economic environment or other facts and
circumstances may necessitate revisions to these assumptions and
could result in a material change to the carrying values of the
Group's assets within the next financial year.
Discount rates
For discounted cash flow calculations, future cash flows are
adjusted for risks specific to the CGU. Fair value less costs of
disposal discounted cash flow calculations use the post-tax
discount rate. The discount rate is derived using the weighted
average cost of capital methodology. The discount rates applied in
impairment tests are reassessed each year and, in 2021, the
post-tax discount rate was 10% (2020: 10%).
Oil prices
The price assumptions used for FVLCD impairment testing were
based on latest internal forecasts as at 31 December 2021, which
assume short-term market prices will revert to the Group's
assessment of long-term price. These price forecasts reflect
EnQuest's long-term views of global supply and demand, including
the potential financial impacts on the Group of climate change and
the transition to a low carbon economy as outlined in the Basis of
Preparation, and are benchmarked with external sources of
information such as analyst forecasts. The Group's price forecasts
are reviewed and approved by management and challenged by the Audit
Committee.
EnQuest revised its oil price assumptions for FVLCD impairment
testing compared to those used in 2020. The assumptions up to 2024
were increased to reflect an improved demand outlook as at the end
of 2021. Oil prices rose 51% in 2021 from 2020 due to a strong
rebound in oil demand as the impact of COVID-19 eased and there
were measured increases in OPEC+ supply combined with continued
capital discipline across the industry impacting supply. A summary
of the Group's revised price assumptions is provided below. These
assumptions, which represent management's best estimate of future
prices, sit within the range of external forecasts and are
considered by EnQuest to be broadly in line with a range of
transition paths consistent with the Paris climate goals. However,
they do not correspond to any specific Paris-consistent scenario.
An inflation rate of 2% (2020: 2%) is applied from 2025 onwards to
determine the price assumptions in nominal terms. 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.
2022 2023 2024 2025>
------------------ ---- ----- ---- ------
Brent oil ($/bbl) 75.0 70.0 70.0 60.0
------------------ ---- ----- ---- ------
The increase in oil prices in the first quarter of 2022 relating
to the Russia-Ukraine conflict is a result of conditions that arose
after the balance sheet date. As such, the Group's future oil price
assumptions used in impairment tests to assess the recoverable
amount of assets at the balance sheet date have not been
adjusted.
A net impairment reversal was recognised in 2021. See note 10
for further information.
The price assumptions used in 2020 were $47.0/bbl (2021),
$55.0/bbl (2022), $60.0/bbl (2023) and $60.0/bbl real thereafter,
inflated at 2.0% per annum from 2024.
Oil and natural gas reserves
Hydrocarbon reserves are estimates of the amount of hydrocarbons
that can be economically and legally extracted from the Group's oil
and gas properties. 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. 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. Economic assumptions used to estimate
reserves change from period to period as additional technical and
operational data is generated. This process may require complex and
difficult geological judgements to interpret the data.
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
intends to develop and it is probable that a market participant
would attribute value to them. Third-party audits of EnQuest's
reserves and resources are conducted annually.
Sensitivity analyses
Management tested the impact of a change in cash flows in FVLCD
impairment testing arising from a 10% reduction in price
assumptions.
Price reductions of this magnitude in isolation could
indicatively lead to a reduction in the carrying amount of
EnQuest's oil and gas properties by approximately $283.5 million,
which is approximately 10% of the net book value of property, plant
and equipment as at 31 December 2021.
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.
Management also tested the impact of a one percentage point
change in the discount rate used for FVLCD impairment testing of
oil and gas properties. If the discount rate was one percentage
point higher across all tests performed, the net impairment
reversal recognised in 2021 would have been approximately $35.1
million lower. If the discount rate was one percentage point lower,
the net impairment reversal recognised would have been
approximately $38.3 million higher.
Goodwill
Irrespective of whether there is any indication of impairment,
EnQuest is required to test annually for impairment of goodwill
acquired in business combinations. The Group carries goodwill of
approximately $134.4 million on its balance sheet (2020: $134.4
million), principally relating to the Magnus oil field
transactions. Sensitivities and additional information relating to
impairment testing of goodwill are provided in note 11.
Deferred tax
The Group assesses the recoverability of its deferred tax assets
at each period end. Sensitivities and additional information
relating to deferred tax assets/liabilities are provided in note
7(d).
75% Magnus acquisition contingent consideration
Sensitivities and additional information relating to the 75%
Magnus acquisition contingent consideration are provided in note
22.
Provisions
Estimates: Decommissioning costs will be incurred by the Group
at the end of the operating life of some of the Group's oil and gas
production facilities and pipelines. The Group assesses its
decommissioning provision at each reporting date. The ultimate
decommissioning costs are uncertain and cost 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 and
experience at other production sites. 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.
The timing and amount of future expenditures relating to
decommissioning and environmental liabilities are reviewed
annually. The interest rate used in discounting the cash flows is
reviewed half-yearly. The nominal interest rate used to determine
the balance sheet obligations at the end of 2021 was 2% (2020: 2%).
The weighted average period over which decommissioning costs are
generally expected to be incurred is estimated to be approximately
ten years. Costs at future prices are determined by applying an
inflation rate of 2% (2020: 2%) to decommissioning costs.
Further information about the Group's provisions is provided in
note 23. Changes in assumptions in relation to the Group's
provisions could result in a material change in their carrying
amounts within the next financial year. A 0.5 percentage point
decrease in the nominal discount rate applied could increase the
Group's provision balances by approximately $40.9 million (2020:
$38.4 million). The pre-tax impact on the Group income statement
would be a charge of approximately $5.9 million.
Intangible oil and gas assets
Judgements: The application of the Group's accounting policy for
exploration and evaluation expenditure requires judgement to
determine whether future economic benefits are likely from either
exploitation or sale, or whether activities have not reached a
stage which permits a reasonable assessment of the existence of
reserves.
3. Segment information
The Group's organisational structure reflects the various
activities in which EnQuest is engaged. Management has considered
the requirements of IFRS 8 Operating Segments in regard to the
determination of operating segments and concluded that at 31
December 2021, the Group had two significant operating segments:
the North Sea and Malaysia. Operations are managed by location and
all information is presented per geographical segment. The Group's
segmental reporting structure remained in place throughout 2021.
The North Sea's activities include Upstream operations,
Decommissioning and Infrastructure & New Energy. Malaysia's
activities include Upstream operations. The Group's reportable
segments may change in the future depending on the way that
resources may be allocated and performance assessed by the Chief
Operating Decision Maker, who for EnQuest is the Chief Executive.
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 2021 Total and
North All other eliminations
$'000 Sea Malaysia segments segments (i) Consolidated
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Revenue:
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Revenue from contracts with customers 1,283,939 99,959 - 1,383,898 - 1,383,898
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Other operating income 3,811 - 235 4,046 (122,130) (118,084)
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Total revenue and other operating
income 1,287,750 99,959 235 1,387,944 (122,130) 1,265,814
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Income/(expenses) line items:
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Depreciation and depletion (299,324) (13,612) (134) (313,070) - (313,070)
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Net impairment (charge)/reversal
to oil and gas assets 39,715 - - 39,715 - 39,715
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Segment profit/(loss) (ii) 653,301 35,625 (291) 688,635 (108,576) 580,059
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Other disclosures:
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Capital expenditure(iii) 459,302 17,419 314 477,035 - 477,035
-------------------------------------- --------- -------- --------- --------- ------------- ------------
Adjustments
Restated Year ended 31 December 2020(iv) Total and
All other
$'000 North Sea Malaysia segments segments eliminations(i) Consolidated
----------------------------------------- --------- -------- --------- --------- ---------------- ------------
Revenue:
----------------------------------------- --------- -------- --------- --------- ---------------- ------------
Revenue from contracts with customers 792,508 62,917 - 855,425 - 855,425
----------------------------------------- --------- -------- --------- --------- ---------------- ------------
Other operating income 5,428 - 280 5,708 2,719 8,427
----------------------------------------- --------- -------- --------- --------- ---------------- ------------
Total revenue and other operating income 797,936 62,917 280 862,929 2,719 863,852
----------------------------------------- --------- -------- --------- --------- ---------------- ------------
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
----------------------------------------- --------- -------- --------- --------- ---------------- ------------
(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 exploration and appraisal assets
(iv) Comparative information for 2020 has been restated for the
changes to the presentation of rental income effective 1 January
2021. For more information, see note 2 Basis of preparation -
Restatements
Reconciliation of profit/(loss):
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
------------------------------------------------------- ------------ ------------
Segment profit/(loss) 688,635 (311,427)
------------------------------------------------------- ------------ ------------
Finance costs (227,846) (257,077)
------------------------------------------------------- ------------ ------------
Finance income 228 1,171
------------------------------------------------------- ------------ ------------
Gain/(loss) on oil and foreign exchange derivatives(i) (108,576) 1,358
------------------------------------------------------- ------------ ------------
Profit/(loss) before tax 352,441 (565,975)
------------------------------------------------------- ------------ ------------
(i) Includes $54.6 million realised losses on derivatives and
$54.0 million unrealised losses on derivatives
Revenue from two 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 $241.7 million and
$150.6 million per each single customer (2020: four customers;
$188.9 million, $143.4 million, $113.1 million and $84.9 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 the 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
remeasurements 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 2021 Fair value and
remeasurement write-offs Other
$'000 (i) (ii) (iii) Total
----------------------------------------------- -------------- ----------- -------- --------
Revenue and other operating income (54,451) - - (54,451)
----------------------------------------------- -------------- ----------- -------- --------
Cost of sales 472 - (7,673) (7,201)
----------------------------------------------- -------------- ----------- -------- --------
Net impairment (charge)/reversal on oil and
gas assets - 39,715 - 39,715
----------------------------------------------- -------------- ----------- -------- --------
Other income 140,079 - 22,568 162,647
----------------------------------------------- -------------- ----------- -------- --------
Other expense - - (3,832) (3,832)
----------------------------------------------- -------------- ----------- -------- --------
Finance costs - - (58,395) (58,395)
----------------------------------------------- -------------- ----------- -------- --------
86,100 39,715 (47,332) 78,483
----------------------------------------------- -------------- ----------- -------- --------
Tax on items above (36,518) (14,722) 24,915 (26,325)
----------------------------------------------- -------------- ----------- -------- --------
Recognition of undiscounted deferred tax asset
(iv) - 104,546 - 104,546
----------------------------------------------- -------------- ----------- -------- --------
49,582 129,539 (22,417) 156,704
----------------------------------------------- -------------- ----------- -------- --------
Impairments
Restated Year ended 31 December 2020 Fair value and
$'000 remeasurement(i) write-offs(ii) Other(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 expenses - - (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
-------------------------------------------- ----------------- --------------- ---------- ---------
Derecognition of undiscounted deferred tax
asset (restated)(iv) - (215,204) - (215,204)
-------------------------------------------- ----------------- --------------- ---------- ---------
87,408 (474,432) (56,734) (443,758)
-------------------------------------------- ----------------- --------------- ---------- ---------
(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 $(54.0) million. Other income relates
to the fair value remeasurement of contingent consideration
relating to the acquisition of Magnus and associated infrastructure
of $140.1 million (note 22) (2020: $138.2 million)
(ii) Impairments and write offs include a net impairment
reversal of tangible oil and gas assets and right-of-use assets
totalling $39.7 million (note 10) (2020: impairment of $422.5
million)
(iii) Other items are made up of the following: Cost of sales
includes $7.7 million mainly related to a provision for a dispute
with a third party contractor. In 2020, cost of sales included
$11.7 million for the provision on the PM8/Seligi riser repair and
redundancy costs in relation to the Group's transformation
programme. Other income in 2021 of $22.6 million (2020: nil)
includes the finalisation of previous asset acquisitions, $12.0
million, and the recognition of insurance income, $9.0 million,
related to the PM8/Seligi riser incident, Other expense $3.8
million relates to expenses incurred on the repayment of the BP
vendor loan and Finance costs relates to Magnus contingent
consideration of $58.3 million (note 22) (2020: $77.3 million).
These are largely non-cash items.
(iv) Non-cash deferred tax recognition (2020 restated see note 2
Basis of preparation - Restatements) following the Group's
acquisition of Golden Eagle and the Group's higher 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 fixed discount rate to an
appropriate benchmark, 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 from vessels, 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
2021 restated
$'000 $'000
----------------------------------------------------------- ------------ ------------
Revenue from contracts with customers:
----------------------------------------------------------- ------------ ------------
Revenue from crude oil sales 1,139,171 779,865
----------------------------------------------------------- ------------ ------------
Revenue from gas and condensate sales(i) 244,073 60,486
----------------------------------------------------------- ------------ ------------
Tariff revenue 654 15,074
----------------------------------------------------------- ------------ ------------
Total revenue from contracts with customers 1,383,898 855,425
----------------------------------------------------------- ------------ ------------
Rental income from vessels(ii) 702 3,910
----------------------------------------------------------- ------------ ------------
Realised (losses)/gains on oil derivative contracts (see
note 19) (67,679) (6,059)
----------------------------------------------------------- ------------ ------------
Other 3,344 1,798
----------------------------------------------------------- ------------ ------------
Business performance revenue and other operating income 1,320,265 855,074
----------------------------------------------------------- ------------ ------------
Unrealised (losses)/gains on oil derivative contracts(iii)
(see note 19) (54,451) 8,778
----------------------------------------------------------- ------------ ------------
Total revenue and other operating income 1,265,814 863,852
----------------------------------------------------------- ------------ ------------
(i) Includes onward sale of third-party gas purchases not
required for injection activities at Magnus
(ii) Comparative information for 2020 has been restated for the
changes to the presentation of rental income effective 1 January
2021. For more information, see note 2 Basis of preparation -
Restatements
(iii) 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 Year ended
31 December 31 December
2021 2020
$'000 $'000
-------------------------------------------- ------------------- -------------------
North
Sea Malaysia North Sea Malaysia
-------------------------------------------- --------- -------- --------- --------
Revenue from contracts with customers:
-------------------------------------------- --------- -------- --------- --------
Revenue from crude oil sales 1,040,577 98,594 719,504 60,361
-------------------------------------------- --------- -------- --------- --------
Revenue from gas and condensate sales(i) 242,708 1,365 57,930 2,556
-------------------------------------------- --------- -------- --------- --------
Tariff revenue 654 - 15,074 -
-------------------------------------------- --------- -------- --------- --------
Total revenue from contracts with customers 1,283,939 99,959 792,508 62,917
-------------------------------------------- --------- -------- --------- --------
(i) Includes onward sale of third-party gas purchases not
required for injection activities at Magnus
(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 IAS 2, 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
2021 2020
$'000 $'000
------------------------------------------------------------------------ ------------ ------------
Production costs 292,252 265,529
------------------------------------------------------------------------ ------------ ------------
Tariff and transportation expenses 39,414 63,685
------------------------------------------------------------------------ ------------ ------------
Realised loss/(gain) on derivative contracts related to operating costs
(see note 19) (10,693) (572)
------------------------------------------------------------------------ ------------ ------------
Change in lifting position 62,868 (31,508)
------------------------------------------------------------------------ ------------ ------------
Crude oil inventory movement (561) (3,293)
------------------------------------------------------------------------ ------------ ------------
Depletion of oil and gas assets(i) 305,578 438,247
------------------------------------------------------------------------ ------------ ------------
Other cost of operations(ii) 211,575 53,367
------------------------------------------------------------------------ ------------ ------------
Business performance cost of sales 900,433 785,455
------------------------------------------------------------------------ ------------ ------------
Unrealised (gains)/losses on derivative contracts related to operating
costs(iii) (see note 19) (472) 1,932
------------------------------------------------------------------------ ------------ ------------
Movement in other provisions 7,673 11,694
------------------------------------------------------------------------ ------------ ------------
Total cost of sales 907,634 799,081
------------------------------------------------------------------------ ------------ ------------
(i) Includes $45.7 million (2020: $68.5 million) Kraken FPSO
right-of-use asset depreciation charge and $14.3 million (2020:
$10.5 million) of other right-of-use assets depreciation charge
(ii) Includes $199.6 million of purchases and associated costs
of third-party gas not required for injection activities at Magnus
which is sold on (2020: $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
2021 2020
$'000 $'000
----------------------------------------------------------- ------------ ------------
Staff costs (see note 5(f)) 80,098 85,813
----------------------------------------------------------- ------------ ------------
Depreciation(i) 7,492 7,616
----------------------------------------------------------- ------------ ------------
Other general and administration costs 21,322 21,831
----------------------------------------------------------- ------------ ------------
Recharge of costs to operations and joint venture partners (108,549) (109,155)
----------------------------------------------------------- ------------ ------------
Total general and administration expenses 363 6,105
----------------------------------------------------------- ------------ ------------
(i) Includes $4.0 million (2020: $3.7 million) right-of-use
assets depreciation charge on buildings
(d) Other income
Year ended
Year ended 31 December
31 December restated(i)
2021 2020
$'000 $'000
----------------------------------------------------------- ------------ ------------
Net foreign exchange gains 391 -
----------------------------------------------------------- ------------ ------------
Gain on termination of Tanjong Baram risk service contract - 10,209
----------------------------------------------------------- ------------ ------------
Change in decommissioning provisions 19,327 -
----------------------------------------------------------- ------------ ------------
Rental income from office sublease(i) 1,702 1,796
----------------------------------------------------------- ------------ ------------
Other 9,570 6,095
----------------------------------------------------------- ------------ ------------
Business performance other income 30,990 18,100
----------------------------------------------------------- ------------ ------------
Fair value changes in contingent consideration (see note
22) 140,079 138,249
----------------------------------------------------------- ------------ ------------
Other non-Business performance 22,568 -
----------------------------------------------------------- ------------ ------------
Total other income 193,637 156,349
----------------------------------------------------------- ------------ ------------
(i) Comparative information for 2020 has been restated for the
changes to the presentation of rental income effective 1 January
2021. For more information, see note 2 Basis of preparation -
Restatements
(e) Other expenses
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
------------------------------------------------------------ ------------ ------------
Net foreign exchange losses - 4,625
------------------------------------------------------------ ------------ ------------
Change in decommissioning provisions - 83,199
------------------------------------------------------------ ------------ ------------
Change in Thistle decommissioning provisions (note 23) 6,184 11,998
------------------------------------------------------------ ------------ ------------
Other 1,094 1,811
------------------------------------------------------------ ------------ ------------
Business performance other expenses 7,278 101,633
------------------------------------------------------------ ------------ ------------
Loss on derecognition of assets related to the Seligi riser
detachment - 956
------------------------------------------------------------ ------------ ------------
Other non-Business performance 3,832 -
------------------------------------------------------------ ------------ ------------
Total other expenses 11,110 102,589
------------------------------------------------------------ ------------ ------------
(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
2021 2020
$'000 $'000
------------------------------------------------------- ------------ ------------
Wages and salaries 71,391 85,913
------------------------------------------------------- ------------ ------------
Social security costs 7,120 9,118
------------------------------------------------------- ------------ ------------
Defined contribution pension costs 5,464 6,871
------------------------------------------------------- ------------ ------------
Expense of share-based payments (see note 21) 6,351 3,401
------------------------------------------------------- ------------ ------------
Other staff costs 12,475 12,781
------------------------------------------------------- ------------ ------------
Total employee costs 102,801 118,084
------------------------------------------------------- ------------ ------------
Contractor costs 33,871 39,371
------------------------------------------------------- ------------ ------------
Total staff costs 136,672 157,455
------------------------------------------------------- ------------ ------------
General and administration staff costs (see note 5(c)) 80,098 85,813
------------------------------------------------------- ------------ ------------
Non-general and administration costs 56,574 71,642
------------------------------------------------------- ------------ ------------
Total staff costs 136,672 157,455
------------------------------------------------------- ------------ ------------
The average number of persons, excluding contractors, employed
by the Group during the year was 734, with 339 in the general and
administration staff costs and 395 directly attributable to assets
(2020: 885 of which 383 in general and administration and 502
directly attributable to assets). Compensation of key management
personnel is disclosed in note 26 and in the remuneration report on
page 84 of the annual report.
(g) Auditor's remuneration
The following amounts for the year ended 31 December 2021 and
for the comparative year ended 31 December 2020 were payable by the
Group to Deloitte:
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
----------------------------------------------------------- ------------ ------------
Fees payable to the Company's auditor for the audit of the
parent company and Group financial statements 847 649
----------------------------------------------------------- ------------ ------------
The audit of the Company's subsidiaries 145 178
----------------------------------------------------------- ------------ ------------
Total audit 992 827
----------------------------------------------------------- ------------ ------------
Audit-related assurance services(i) 1,419 180
----------------------------------------------------------- ------------ ------------
Total audit and audit-related assurance services 2,411 1,007
----------------------------------------------------------- ------------ ------------
Tax services - 10
----------------------------------------------------------- ------------ ------------
Total auditor's remuneration 2,411 1,017
----------------------------------------------------------- ------------ ------------
(i) Audit-related assurance services include the review of the
Group's interim results and audit and assurance work in respect of
the Group's Golden Eagle acquisition
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
2021 2020
$'000 $'000
---------------------------------------------------------- ------------ ------------
Finance costs:
---------------------------------------------------------- ------------ ------------
Loan interest payable 20,206 32,791
---------------------------------------------------------- ------------ ------------
Bond interest payable 69,085 73,476
---------------------------------------------------------- ------------ ------------
Unwinding of discount on decommissioning provisions (see
note 23) 15,856 14,512
---------------------------------------------------------- ------------ ------------
Unwinding of discount on other provisions (see note 23) 1,061 796
---------------------------------------------------------- ------------ ------------
Finance charges payable under leases 45,359 50,851
---------------------------------------------------------- ------------ ------------
Amortisation of finance fees on loans and bonds 13,623 5,417
---------------------------------------------------------- ------------ ------------
Other financial expenses 4,261 1,975
---------------------------------------------------------- ------------ ------------
Business performance finance expenses 169,451 179,818
---------------------------------------------------------- ------------ ------------
Finance costs on Magnus-related contingent consideration
(see note 22) 58,395 77,259
---------------------------------------------------------- ------------ ------------
Total finance costs 227,846 257,077
---------------------------------------------------------- ------------ ------------
Finance income:
---------------------------------------------------------- ------------ ------------
Bank interest receivable 228 896
---------------------------------------------------------- ------------ ------------
Unwinding of discount on financial asset (see note 19(f)) - 275
---------------------------------------------------------- ------------ ------------
Total finance income 228 1,171
---------------------------------------------------------- ------------ ------------
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.
The major components of income tax (credit)/expense are as
follows:
Year ended
Year ended 31 December
31 December 2020
2021 restated
$'000 $'000
-------------------------------------------------------------- ------------ ------------
Current UK income tax
-------------------------------------------------------------- ------------ ------------
Current income tax charge 3,559 -
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of current income tax of previous
years 199 140
-------------------------------------------------------------- ------------ ------------
Current overseas income tax
-------------------------------------------------------------- ------------ ------------
Current income tax charge 18,050 2,424
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of current income tax of previous
years (221) (295)
-------------------------------------------------------------- ------------ ------------
Total current income tax 21,587 2,269
-------------------------------------------------------------- ------------ ------------
Deferred UK income tax
-------------------------------------------------------------- ------------ ------------
Relating to origination and reversal of temporary differences (43,325) (97,673)
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of changes in tax rates - 1
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of deferred income tax of previous
years 157 2,660
-------------------------------------------------------------- ------------ ------------
Deferred overseas income tax
-------------------------------------------------------------- ------------ ------------
Relating to origination and reversal of temporary differences (5,320) (5,135)
-------------------------------------------------------------- ------------ ------------
Adjustments in respect of deferred income tax of previous
years 2,354 1,848
-------------------------------------------------------------- ------------ ------------
Total deferred income tax (46,134) (98,299)
-------------------------------------------------------------- ------------ ------------
Income tax (credit)/expense reported in profit or loss (24,547) (96,030)
-------------------------------------------------------------- ------------ ------------
(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
2021 restated(i)
$'000 $'000
------------------------------------------------------------------- ------------ ------------
Profit/(loss) before tax 352,441 (565,975)
------------------------------------------------------------------- ------------ ------------
UK statutory tax rate applying to North Sea oil and gas activities
of 40% (2020: 40%) 140,976 (226,390)
------------------------------------------------------------------- ------------ ------------
Supplementary corporation tax non-deductible expenditure 4,331 17,761
------------------------------------------------------------------- ------------ ------------
Petroleum revenue tax (net of income tax benefit) 2,548 (2,548)
------------------------------------------------------------------- ------------ ------------
Non-deductible expenditure/income (1,442) (3,449)
------------------------------------------------------------------- ------------ ------------
North Sea tax reliefs (113,593) (106,685)
------------------------------------------------------------------- ------------ ------------
Tax in respect of non-ring-fence trade 23,378 3,222
------------------------------------------------------------------- ------------ ------------
Deferred tax asset (recognition)/impairment in respect of
non-ring-fence trade 21,241 3,515
------------------------------------------------------------------- ------------ ------------
Deferred tax asset (recognition)/impairment in respect of
ring-fence trade (104,546) 215,204
------------------------------------------------------------------- ------------ ------------
Adjustments in respect of prior years 2,489 4,352
------------------------------------------------------------------- ------------ ------------
Overseas tax rate differences (594) (1,250)
------------------------------------------------------------------- ------------ ------------
Share-based payments 1,526 1,097
------------------------------------------------------------------- ------------ ------------
Other differences (861) (859)
------------------------------------------------------------------- ------------ ------------
At the effective income tax rate of 7% (2020: 17%) (24,547) (96,030)
------------------------------------------------------------------- ------------ ------------
(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 2020
2021 restated(i) 2021 restated(i)
$'000 $'000 $'000 $'000
------------------------------------------- ----------- ------------ -------- ------------
Deferred tax liability
------------------------------------------- ----------- ------------ -------- ------------
Accelerated capital allowances 768,630 821,253 (52,623) (236,551)
------------------------------------------- ----------- ------------ -------- ------------
768,630 821,253
------------------------------------------- ----------- ------------ -------- ------------
Deferred tax asset
------------------------------------------- ----------- ------------ -------- ------------
Losses (1,017,107) (981,445) (35,653) 121,089
------------------------------------------- ----------- ------------ -------- ------------
Decommissioning liability (286,045) (310,697) 24,652 (26,640)
------------------------------------------- ----------- ------------ -------- ------------
Other temporary differences (165,030) (182,529) 17,490 43,803
------------------------------------------- ----------- ------------ -------- ------------
(1,468,182) (1,474,671) (46,133) (98,299)
------------------------------------------- ----------- ------------ -------- ------------
Net deferred tax (assets) (699,552) (653,418)
------------------------------------------- ----------- ------------ -------- ------------
Reflected in the balance sheet as follows:
------------------------------------------- ----------- ------------ -------- ------------
Deferred tax assets (702,970) (659,803)
------------------------------------------- ----------- ------------ -------- ------------
Deferred tax liabilities 3,418 6,385
------------------------------------------- ----------- ------------ -------- ------------
Net deferred tax (assets) (699,552) (653,418)
------------------------------------------- ----------- ------------ -------- ------------
Reconciliation of net deferred tax assets/(liabilities)
2020
2021 restated(i)
$'000 $'000
------------------------------------------------------------ ------- ------------
At 1 January 653,418 555,119
------------------------------------------------------------ ------- ------------
Tax income/(expense) during the period recognised in profit
or loss 46,134 98,299
------------------------------------------------------------ ------- ------------
At 31 December 699,552 653,418
------------------------------------------------------------ ------- ------------
(i) Comparative information for 2020 has been restated for the
changes to the presentation of rental income effective 1 January
2021. For more information, see note 2 Basis of preparation -
Restatements
(d) Tax losses
The Group's deferred tax assets at 31 December 2021 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. A $127.6 million tax credit has been recognised as an
exceptional item, reflecting the reversal of the previous deferred
tax asset derecognition. 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 a reasonable
possible change for the purposes of sensitivity analysis (see note
2). A 10% reduction in oil price would result in a deferred tax
asset derecognition of $318.6 million and a 10% increase in oil
price would result in an increase in deferred tax asset recognition
of $107.9 million.
The Group has unused UK mainstream corporation tax losses of
$431.7 million (2020: $320.7 million), and ring-fence tax losses of
$957.8 million associated with the Bentley acquisition, for which
no deferred tax asset has been recognised at the balance sheet date
as recovery of these losses is to be established. 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 and the remaining benefit of
$12.9 million (2020: $15.1 million) remaining unrecognised.
The Group has unused overseas tax losses in Canada of
approximately CAD$13.5 million (2020: 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 2021, and which arose following the change
in control of the Stratic Group in 2010.
The Group has unused Malaysian income tax losses of $15.7
million (2020: $14.3 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. The Finance Act 2009 exempted foreign
dividends from the scope of UK corporation tax where certain
conditions are satisfied.
(e) Changes in legislation
The 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 2020
2021 restated(ii) 2021 2020 2021 restated(ii)
$'000 $'000 million million $ $
-------------------------------------- -------- -------------- ---------- --------- ------ -------------
Basic 376,988 (469,945) 1,736.4 1,655.0 0.217 (0.290)
-------------------------------------- -------- -------------- ---------- --------- ------ -------------
Dilutive potential of Ordinary shares
granted under share-based incentive
schemes - - 24.7 15.1 - -
-------------------------------------- -------- -------------- ---------- --------- ------ -------------
Diluted(i) 376,988 (469,945) 1,761.1 1,670.1 0.214 (0.290)
-------------------------------------- -------- -------------- ---------- --------- ------ -------------
Basic (excluding remeasurements and
exceptional items) 220,284 (26,187) 1,736.4 1,655.0 0.127 (0.016)
-------------------------------------- -------- -------------- ---------- --------- ------ -------------
Diluted (excluding remeasurements
and exceptional items)(i) 220,284 (26,187) 1,761.1 1,670.1 0.125 (0.016)
-------------------------------------- -------- -------------- ---------- --------- ------ -------------
(i) Potential Ordinary shares are not treated as dilutive when
they would decrease a loss per share
(ii) 2020 comparative restated, see note 2 Basis of preparation - Restatements
9. Dividends paid and proposed
The Company paid no dividends during the year ended 31 December
2021 (2020: none). At 31 December 2021, there are no proposed
dividends (2020: 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
Group 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 Five years
and equipment
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 is reviewed and adjusted if appropriate at each
financial year end. No depreciation is charged on assets under
construction.
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 life of a field depends on
the interaction of a number of variables such as the recoverable
quantity of hydrocarbons, the production profile of the
hydrocarbons, the capex necessary to recover the hydrocarbons,
production costs and the selling price of the hydrocarbons
produced. Estimated production volumes and cash flows up to the
date of cessation of production on a field-by-field basis,
including operating and capital expenditure, are derived from the
Group's business plan. Oil price assumptions and discount rate
assumptions used were as disclosed in note 2. 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.
Office
Oil furniture, Right-of-use
fixtures
and gas and assets
(note
assets fittings 24) Total
$'000 $'000 $'000 $'000
---------------------------------------------------- ---------- ------------ ------------ ----------
Cost:
---------------------------------------------------- ---------- ------------ ------------ ----------
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 10,200 - - 10,200
---------------------------------------------------- ---------- ------------ ------------ ----------
Disposals and termination of Tanjong Baram
risk service contract (84,724) (143) (1,412) (86,279)
---------------------------------------------------- ---------- ------------ ------------ ----------
At 1 January 2021 8,552,171 64,220 858,489 9,474,880
---------------------------------------------------- ---------- ------------ ------------ ----------
Acquisition 386,210 - - 386,210
---------------------------------------------------- ---------- ------------ ------------ ----------
Additions 61,704 1,165 17,815 80,684
---------------------------------------------------- ---------- ------------ ------------ ----------
Change in decommissioning provision (2,732) - - (2,732)
---------------------------------------------------- ---------- ------------ ------------ ----------
Disposal - - (8,411) (8,411)
---------------------------------------------------- ---------- ------------ ------------ ----------
At 31 December 2021 8,997,353 65,385 867,893 9,930,631
---------------------------------------------------- ---------- ------------ ------------ ----------
Accumulated depreciation, depletion and impairment:
---------------------------------------------------- ---------- ------------ ------------ ----------
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 (42,958) (113) (706) (43,777)
---------------------------------------------------- ---------- ------------ ------------ ----------
Impairment charge for the year 314,335 - 108,160 422,495
---------------------------------------------------- ---------- ------------ ------------ ----------
At 1 January 2021 6,428,559 50,357 362,047 6,840,963
---------------------------------------------------- ---------- ------------ ------------ ----------
Charge for the year 245,645 3,472 63,953 313,070
---------------------------------------------------- ---------- ------------ ------------ ----------
Net impairment reversal for the year (24,046) - (15,669) (39,715)
---------------------------------------------------- ---------- ------------ ------------ ----------
Disposal - - (5,831) (5,831)
---------------------------------------------------- ---------- ------------ ------------ ----------
Other 146 - - 146
---------------------------------------------------- ---------- ------------ ------------ ----------
At 31 December 2021 6,650,304 53,829 404,500 7,108,633
---------------------------------------------------- ---------- ------------ ------------ ----------
Net carrying amount:
---------------------------------------------------- ---------- ------------ ------------ ----------
At 31 December 2021 2,347,049 11,556 463,393 2,821,998
---------------------------------------------------- ---------- ------------ ------------ ----------
At 31 December 2020 2,123,612 13,863 496,442 2,633,917
---------------------------------------------------- ---------- ------------ ------------ ----------
At 1 January 2020 2,749,845 15,885 685,199 3,450,929
---------------------------------------------------- ---------- ------------ ------------ ----------
The amount of borrowing costs capitalised during the year ended
31 December 2021 was nil (2020: nil).
Acquisitions
The Group acquired a 26.69% non-operated interest in the
producing Golden Eagle area from Suncor Energy UK on 22 October
2021. The Group applied the optional concentration test for this
transaction in accordance with IFRS 3. Accordingly, it has been
concluded that as substantially all of the value arising from the
transaction relates to the producing oil and gas asset, the
acquired assets do not represent a business and therefore the
transaction has been accounted for as an asset acquisition at cost.
Consideration included cash of $249.7 million and a contingent
payment based on the average oil price between July 2021 and June
2023. The Net Present Value of the contingent payment has been
valued at $44.7 million and has been included within contingent
consideration (see note 22). Other directly attributable costs of
$10.4 million were also included in the cost of the acquisition.
The total oil and gas asset recognised in relation to the
acquisition is $386.2 million. A decommissioning liability of
$119.3 million was also recognised as part of the acquisition (see
note 23).
Impairments
Impairments to the Group's producing assets and reversals of
impairments are set out in the table below:
Impairment Recoverable
(charge)/reversal amount(i)
----------------------------------------- -------------------------- ------------------------
Year ended Year ended
31 December 31 December 31 December 31 December
2021 2020 2021 2020
$'000 $'000 $'000 $'000
----------------------------------------- ------------ ------------ ----------- -----------
North Sea 39,715 (422,495) 1,496,219 1,518,832
----------------------------------------- ------------ ------------ ----------- -----------
Net pre-tax impairment reversal/(charge) 39,715 (422,495)
----------------------------------------- ------------ ------------ ----------- -----------
(i) Recoverable amount has been determined on a fair value less
costs of disposal basis (see note 2 for further details of
judgements, estimates and assumptions 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
For information on judgements, estimates and assumptions made in
relation to impairments see 'Use of judgements, estimates and
assumptions' within note 2.
The 2021 net impairment reversal of $39.7 million relates to
producing assets in the UK North Sea. Impairment reversals were
primarily driven by an increase in EnQuest's near-term future oil
price assumptions. The CGUs on which impairment reversals relate
were $53.7 million for Kraken and $6.1 million for Alba. In
addition, impairment losses of $20.1 million were incurred relating
to the GKA and Scolty/Crathes CGU, primarily as a result of
forecast increased costs and lower production.
The 2020 impairment charge of $422.5 million related to
producing assets in the UK North Sea. Impairment losses were
primarily driven by a reduction in EnQuest's future oil price
assumptions and the decision to cease production at Dons. The
principal CGUs on which significant impairment losses were incurred
in 2020 were $380.3 million for Kraken, $28.2 million for Alba and
$14.6 million for Dons.
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. For information on
significant estimates and judgements made in relation to
impairments see Use of judgements, estimates and assumptions:
recoverability of asset carrying values within note 2.
A summary of goodwill is presented below:
2021 2020
$'000 $'000
----------------------------- ------- --------
Cost and net carrying amount
----------------------------- ------- --------
At 1 January 134,400 134,400
----------------------------- ------- --------
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, based on current estimates of reserves and resources,
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 life of a field depends on the interaction
of a number of variables such as the recoverable quantity of
hydrocarbons, the production profile of the hydrocarbons, the capex
necessary to recover the hydrocarbons, production costs and the
selling price of the hydrocarbons produced. Estimated production
volumes and cash flows up to the date of cessation of production on
a field-by-field basis, including operating and capital
expenditure, are derived from the Group's business plan. Oil price
assumptions and discount rate assumptions used were as disclosed in
note 2. An impairment charge of nil was taken in 2021 (2020: nil)
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%
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 a net impairment of $54.7 million (2020:
10% reduction would result in a net impairment of $14.0 million). A
20% reduction in oil price would fully impair goodwill (2020:
13%).
12. Intangible assets
Accounting policy
Exploration and appraisal assets
Exploration and appraisal assets 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 2021, there was no impairment
of historical exploration and appraisal expenditures (2020:
nil).
Other intangibles
UK emissions allowances ('UKAs') purchased to settle the Group's
liability related to emissions are recognised on the balance sheet
as an intangible asset at cost. The UKAs will be derecognised upon
settling the liability with the respective regulator.
Exploration UK emissions
and appraisal allowances
assets $'000 Total
$'000 $'000
---------------------------------------------- -------------- ------------ ---------
Cost:
---------------------------------------------- -------------- ------------ ---------
At 1 January 2020 174,964 - 174,964
---------------------------------------------- -------------- ------------ ---------
Write-off of relinquished licences previously
impaired (12,645) - (12,645)
---------------------------------------------- -------------- ------------ ---------
Other (7) - (7)
---------------------------------------------- -------------- ------------ ---------
At 1 January 2021 162,312 - 162,312
---------------------------------------------- -------------- ------------ ---------
Additions 10,141 10,052 20,193
---------------------------------------------- -------------- ------------ ---------
Write-off of relinquished licences previously
impaired (72) - (72)
---------------------------------------------- -------------- ------------ ---------
At 31 December 2021 172,381 10,052 182,433
---------------------------------------------- -------------- ------------ ---------
Accumulated impairment:
---------------------------------------------- -------------- ------------ ---------
At 1 January 2020 (147,411) - (147,411)
---------------------------------------------- -------------- ------------ ---------
Write-off of relinquished licences previously
impaired 12,645 - 12,645
---------------------------------------------- -------------- ------------ ---------
At 1 January 2021 (134,766) - (134,766)
---------------------------------------------- -------------- ------------ ---------
At 31 December 2021 (134,766) - (134,766)
---------------------------------------------- -------------- ------------ ---------
Net carrying amount:
---------------------------------------------- -------------- ------------ ---------
At 31 December 2021 37,615 10,052 47,667
---------------------------------------------- -------------- ------------ ---------
At 31 December 2020 27,546 - 27,546
---------------------------------------------- -------------- ------------ ---------
At 1 January 2020 27,553 - 27,553
---------------------------------------------- -------------- ------------ ---------
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.
2021 2020
$'000 $'000
------------------------ ------ -------
Hydrocarbon inventories 22,835 20,509
------------------------ ------ -------
Well supplies 50,188 39,275
------------------------ ------ -------
73,023 59,784
------------------------ ------ -------
During 2021, a net gain of $0.4 million was recognised within
cost of sales in the Group income statement relating to inventory
(2020: charge of $21.6 million).
The inventory valuation at 31 December 2021 is stated net of a
provision of $43.2 million (2020: $56.7 million) to write down well
supplies to their estimated net realisable value. During the year a
portion of the provided for well supplies was disposed of,
resulting in a net charge to the income statement of $0.2 million
(2020: $24.9 million).
14. Cash and cash equivalents
Accounting policy
Cash and cash equivalents includes cash at bank, cash in hand,
outstanding bank overdrafts and highly liquid interest-bearing
securities with original maturities of three months or fewer.
2021 2020
$'000 $'000
-------------------------- ------- --------
Available cash 276,970 221,155
-------------------------- ------- --------
Restricted cash 9,691 1,675
-------------------------- ------- --------
Cash and Cash Equivalents 286,661 22,830
-------------------------- ------- --------
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.
Restricted cash
Included within the cash balance at 31 December 2021 is
restricted cash of $9.7 million. This includes $8.2 million on
deposit relating to bank guarantees for the Group's Malaysian
assets and $1.5 million related to cash collateralised letters of
credit. In 2020, the restricted cash balance of $1.7 million
related to cash held in escrow in respect of the unwound
acquisition of the Tunisian assets of PA resources. This balance
was fully collected in 2021.
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 are based on
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 when they become 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.
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
are 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 2021 Notes $'000 $'000 $'000 $'000
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Financial assets measured at fair value:
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Derivative financial assets measured at
FVPL
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Forward UKAs contracts 90 - 90 -
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Forward foreign currency contracts 382 - 382 -
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Other financial assets measured at FVPL
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Quoted equity shares 6 6 - -
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Total financial assets measured at fair
value 478 6 472 -
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Liabilities measured at fair value:
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Derivative financial liabilities measured
at FVPL
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Oil commodity derivative contracts 19 55,247 - 55,247 -
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Other financial liabilities measured at
FVPL
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Contingent consideration 22 410,778 - - 410,778
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Total liabilities measured at fair value 466,025 - 55,247 410,778
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Liabilities measured at amortised cost
for which fair values are disclosed below:
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Interest-bearing loans and borrowings 18 424,864 - - 424,864
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Obligations under leases 24 570,781 - - 570,781
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Retail bond 18 244,387 244,387 - -
-------------------------------------------- ----- ---------- ---------- ----------- -------------
High yield bond 18 773,499 773,499 - -
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Total liabilities measured at amortised
cost for which fair values are disclosed 2,013,531 1,017,886 - 995,645
-------------------------------------------- ----- ---------- ---------- ----------- -------------
Quoted
prices Significant Significant
in active observable unobservable
markets inputs inputs
(Level (Level (Level
Total 1) 2) 3)
31 December 2020 Notes $'000 $'000 $'000 $'000
-------------------------------------------- ----- --------- ---------- ----------- -------------
Financial assets measured at fair value:
-------------------------------------------- ----- --------- ---------- ----------- -------------
Other financial assets at FVPL
-------------------------------------------- ----- --------- ---------- ----------- -------------
Quoted equity shares 7 7 - -
-------------------------------------------- ----- --------- ---------- ----------- -------------
Total financial assets measured at fair
value 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
-------------------------------------------- ----- --------- ---------- ----------- -------------
Total liabilities measured at fair value 524,268 2,007 522,261
-------------------------------------------- ----- --------- ---------- ----------- -------------
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 - -
-------------------------------------------- ----- --------- ---------- ----------- -------------
Total liabilities measured at amortised
cost for which fair values are disclosed 1,865,600 763,545 - 1,102,055
-------------------------------------------- ----- --------- ---------- ----------- -------------
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 (2020: no transfers).
For the financial liabilities measured at amortised cost 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
2021 2020
$'000 $'000
------------------------------- ------- -------
Current
------------------------------- ------- -------
Trade receivables 94,992 24,604
------------------------------- ------- -------
Joint venture receivables 68,157 53,121
------------------------------- ------- -------
Under-lift position 35,769 15,690
------------------------------- ------- -------
VAT receivable - 10,307
------------------------------- ------- -------
Other receivables 11,703 1,441
------------------------------- ------- -------
210,621 105,163
------------------------------- ------- -------
Prepayments and accrued income 85,447 13,552
------------------------------- ------- -------
296,068 118,715
------------------------------- ------- -------
The carrying values 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 2021 or 2020. The Group's ECL estimates were not
significantly impacted by COVID-19 during 2021.
17. Trade and other payables
2021 2020
$'000 $'000
------------------------ ------- -------
Current
------------------------ ------- -------
Trade payables 49,701 41,090
------------------------ ------- -------
Accrued expenses 297,744 179,590
------------------------ ------- -------
Over-lift position 53,742 12,732
------------------------ ------- -------
Joint venture creditors 10,852 16,647
------------------------ ------- -------
VAT payable 7,561 -
------------------------ ------- -------
Other payables 944 5,096
------------------------ ------- -------
420,544 255,155
------------------------ ------- -------
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
2021 2020
$'000 $'000
----------- --------- ---------
Borrowings 401,614 452,284
----------- --------- ---------
Bonds 1,081,596 1,045,041
----------- --------- ---------
1,483,210 1,497,325
----------- --------- ---------
(a) Borrowings
The Group's borrowings are carried at amortised cost as
follows:
2021 2020
----------------------------- ---------------------------- ----------------------------
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
----------------------------- --------- -------- ------- --------- ------- --------
RBL 415,000 (23,250) 391,750 - - -
----------------------------- --------- -------- ------- --------- ------- --------
Credit facility - - - 377,270 - 377,270
----------------------------- --------- -------- ------- --------- ------- --------
Sculptor Capital facility - - - 67,701 (1,925) 65,776
----------------------------- --------- -------- ------- --------- ------- --------
SVT working capital facility 9,864 - 9,864 9,238 - 9,238
----------------------------- --------- -------- ------- --------- ------- --------
Total borrowings 424,864 (23,250) 401,614 454,209 (1,925) 452,284
----------------------------- --------- -------- ------- --------- ------- --------
Due within one year 210,505 414,430
----------------------------- --------- -------- ------- --------- ------- --------
Due after more than one year 191,109 37,854
----------------------------- --------- -------- ------- --------- ------- --------
Total borrowings 401,614 452,284
----------------------------- --------- -------- ------- --------- ------- --------
See liquidity risk - note 27 for the timing of cash outflows
relating to loans and borrowings.
RBL facility
On 11 June 2021, the Group signed a new RBL facility of
approximately $600.0 million and an additional amount of $150.0
million for letters of credit for up to seven years. Upon
refinancing of the Group's existing high yield bonds, the maturity
of the new facility is extended to the earlier of seven years from
its signing date, or the point at which the remaining economic
reserves for all borrowing base assets are projected to fall below
25% of the initial economic reserves forecast. In the event the
maturity of the new facility is not extended, any amounts drawn
amortise such that they are fully repaid by the end of September
2023. In 2021 interest accrued at a rate of 4.25% plus USD LIBOR.
From 1 January 2022, following the IBOR transition, interest will
accrue at a rate of 4.25% plus a margin. The margin will be a
combination of a fixed rate based on the interest period and SOFR.
From October 2022, the fixed rate percentage will increase from
4.25% to 4.50%.
During 2021 the Group utilised $485.0 million of the RBL, $360.0
million in July and $125.0 million in October. In December 2021,
the Group voluntarily repaid $70.0 million ahead of the planned
amortisation schedule. As at 31 December 2021, the carrying value
of the facility was $391.8 million, comprising the principal of
$415.0 million and unamortised fees of $23.3 million.
At 31 December 2021, after allowing for letter of credit
utilisation of $53.0 million, $32.0 million remained available for
drawdown under the credit facility.
Credit facility
During the period, the Group repaid its outstanding debt on the
Credit facility of $378.1 million.
Sculptor Capital facility
During the period, the Group repaid its outstanding debt on the
Sculptor Capital facility of $67.7 million.
SVT working capital facility
On 1 December 2020, EnQuest 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
guaranteed by BP EOC Limited. The facility is able to be drawn down
against, in instalments, and accrues interest at 1.0% per annum
plus GBP LIBOR.
(b) Bonds
The Group's bonds are carried at amortised cost as follows:
2021 2020
------------------------------------ ----------------------------- -------------------------------
Principal Fees Total Principal Fees Total
$'000 $'000 $'000 $'000 $'000 $'000
------------------------------------ --------- ------- --------- ---------- ------- ----------
High yield bond 827,166 (1,725) 825,441 799,194 (2,666) 796,528
------------------------------------ --------- ------- --------- ---------- ------- ----------
Retail bond 256,574 (419) 256,155 249,161 (648) 248,513
------------------------------------ --------- ------- --------- ---------- ------- ----------
Total bonds due after more than one
year 1,083,740 (2,144) 1,081,596 1,048,355 (3,314) 1,045,041
------------------------------------ --------- ------- --------- ---------- ------- ----------
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 2020, 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 above carrying value of the bond as at 31 December 2021 is
$825.4 million (2020: $796.5 million). This includes bond principal
of $827.2 million (2020: $799.2 million) less unamortised fees of
$1.7 million (2020: $2.7 million). The high yield bond does not
include accrued interest of $12.2 million (2020: $11.8 million) and
liability for the IFRS 9 Financial Instruments loss on modification
of $2.6 million (2020: $4.6 million), which are reported within
trade and other payables. The fair value of the high yield bond is
disclosed in note 15.
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 2020, 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 above carrying value of the bond as at 31 December 2021 is
$256.2 million (2020: $248.5 million). This includes bond principal
of $256.6 million (2020: $249.2 million) less unamortised fees of
$0.4 million (2020: $0.6 million). The retail yield bond does not
include accrued interest of $6.2 million (2020: $6.3 million) and
liability for the IFRS 9 Financial Instruments loss on modification
of $7.4 million (2020: $11.9 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
2021 2020
-------------------------------------- ------------------- -------------------
Assets Liabilities Assets Liabilities
$'000 $'000 $'000 $'000
-------------------------------------- ------ ----------- ------ -----------
Fair value through profit or loss:
-------------------------------------- ------ ----------- ------ -----------
Derivative commodity contracts - 55,245 - 2,007
-------------------------------------- ------ ----------- ------ -----------
Derivative foreign exchange contracts 382 - - -
-------------------------------------- ------ ----------- ------ -----------
Commodity futures - 2 - -
-------------------------------------- ------ ----------- ------ -----------
Derivative UKAs contracts 90 - - -
-------------------------------------- ------ ----------- ------ -----------
Total current 472 55,247 - 2,007
-------------------------------------- ------ ----------- ------ -----------
Fair value through profit or loss:
-------------------------------------- ------ ----------- ------ -----------
Quoted equity shares 6 - 7 -
-------------------------------------- ------ ----------- ------ -----------
Total non-current 6 - 7 -
-------------------------------------- ------ ----------- ------ -----------
(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 2021 $'000 $'000 $'000 $'000
---------------------------- -------- ---------- -------- ----------
Commodity options (62,016) (55,570) - -
---------------------------- -------- ---------- -------- ----------
Commodity swaps (4,258) 1,121 - -
---------------------------- -------- ---------- -------- ----------
Commodity futures 985 (2) - -
---------------------------- -------- ---------- -------- ----------
Foreign exchange contracts - - (4) 382
---------------------------- -------- ---------- -------- ----------
UKA contracts - - 10,697 90
---------------------------- -------- ---------- -------- ----------
(65,289) (54,451) 10,693 472
---------------------------- -------- ---------- -------- ----------
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)
---------------------------- -------- ---------- -------- ----------
(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 2021, losses totalling $119.7
million (2020: gains of $2.7 million) were recognised in respect of
commodity contracts designated as FVPL. This included losses
totalling $65.3 million (2020: losses of $6.1 million) realised on
contracts that matured during the year, and mark-to-market
unrealised losses totalling $54.5 million (2020: gains of $8.8
million). Of the realised amounts recognised during the year, a
loss of $1.0 million (2020: gain of $6.2 million) was realised in
Business performance revenue in respect of the premium expense
received on sale of these options.
The mark-to-market value of the Group's open commodity contracts
as at 31 December 2021 was a liability of $55.2 million (2020:
liability of $2.0 million).
(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 2021, gains totalling $0.4 million (2020: losses of $1.4
million) were recognised in the Group income statement. This
included realised gains totalling $0.1 million (2020: gains of $0.6
million) on contracts that matured in the year.
The mark-to-market value of the Group's open contracts as at 31
December 2021 was $0.4 million (2020: nil).
(e) UK emissions allowance forward contracts
The Group enters into forward contracts for the purchase of UKAs
to manage its exposure to price. In 2020 these contracts were
treated as own use contracts and not accounted for as derivatives.
During 2021 a number of open contracts were closed out early. The
result of this was the Group no longer being able to account for
UKAs forwards as own use and recognising them as derivatives.
During the year ended 31 December 2021, gains totalling $10.8
million (2020: nil) were recognised in the income statement. This
included realised gains totalling $10.7 million (2020: nil) on
contracts that matured in the year.
The mark-to-market value of the Group's open contracts as at 31
December 2021 was $0.1 million (2020: nil).
(f) Other receivables
2021 2020
$'000 $'000
------------------------- ------ -------
At 1 January 7 6,874
------------------------- ------ -------
Change in fair value (1) (4)
------------------------- ------ -------
Utilised during the year - (7,138)
------------------------- ------ -------
Unwinding of discount - 275
------------------------- ------ -------
At 31 December 6 7
------------------------- ------ -------
Non-current 6 7
------------------------- ------ -------
6 7
------------------------- ------ -------
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.
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 2021 1,695,801,955 118,271 227,149 345,420
Issuance of equity shares 190,122,384 13,379 37,346 50,725
Expenses of issuance of equity shares - - (3,949) (3,949)
-------------------------------------- -------------- -------- -------- --------
At 31 December 2021 1,885,924,339 131,650 260,546 392,196
-------------------------------------- -------------- -------- -------- --------
At 31 December 2021, there were 39,718,323 shares held by the
Employee Benefit Trust (2020: 46,492,546). On 26 July 2021,
2,159,903 shares were acquired by the Employee Benefit Trust
pursuant to the firm placing, placing and open offer. The remaining
movement in the year was due to shares used to satisfy awards made
under the Company's share-based incentive schemes.
On 26 July 2021, the Group completed a firm placing, placing and
open offer pursuant to which 190,122,384 new Ordinary shares were
issued at a price of GBP0.19 per share, generating gross aggregate
proceeds of $50.7 million. Following the admission to the market of
an additional 190,122,384 Ordinary shares on 26 July 2021, there
were 1,885,924,339 Ordinary shares in issue at the end of the
year.
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.
Information on these plans for Directors is shown in the
Directors' remuneration report on pages 76 to 93 of the annual
report.
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 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 Group operates a number of equity-settled employee share
plans under which share units are granted to the Group's senior
leaders and certain other employees. These plans typically have a
three-year performance or restricted period. Leaving employment
will normally preclude the conversion of units into shares, but
special arrangements apply for participants that leave for
qualifying reasons.
The share-based payment expense recognised for each scheme was
as follows:
2021 2020
$'000 $'000
------------------------------ ------ ------
Performance Share Plan 5,241 3,277
------------------------------ ------ ------
Other performance share plans 135 364
------------------------------ ------ ------
Sharesave Plan 975 (240)
------------------------------ ------ ------
6,351 3,401
------------------------------ ------ ------
The following table shows the number of shares potentially
issuable under equity-settled employee share plans, including the
number of options outstanding and the number of options exercisable
at the end of each year.
2021 2020
Share plans Number Number
--------------------------- ------------ ------------
Outstanding at 1 January 110,263,670 77,374,961
--------------------------- ------------ ------------
Granted during the year 35,552,383 53,223,408
--------------------------- ------------ ------------
Exercised during the year (8,056,525) (6,288,132)
--------------------------- ------------ ------------
Forfeited during the year (12,265,533) (14,046,567)
--------------------------- ------------ ------------
Outstanding at 31 December 125,493,995 110,263,670
--------------------------- ------------ ------------
Exercisable at 31 December 14,249,920 11,894,904
--------------------------- ------------ ------------
In addition, the Group operates an approved savings-related
share option scheme (the Sharesave Plan). 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 following table shows the number of shares potentially
issuable under equity-settled employee share option plans,
including the number of options outstanding, the number of options
exercisable at the end of each year and the corresponding weighted
average exercise prices.
2021 2020
Weighted Weighted
average average
exercise exercise
Share options Number price $ Number price $
--------------------------- ----------- --------- ------------ ---------
Outstanding at 1 January 42,383,654 0.13 42,589,522 0.16
--------------------------- ----------- --------- ------------ ---------
Granted during the year 1,370,748 0.25 34,719,941 0.13
--------------------------- ----------- --------- ------------ ---------
Exercised during the year (885,646) 0.10 (452,545) 0.14
--------------------------- ----------- --------- ------------ ---------
Forfeited during the year (5,349,829) 0.15 (34,473,264) 0.17
--------------------------- ----------- --------- ------------ ---------
Outstanding at 31 December 37,518,927 0.14 42,383,654 0.13
--------------------------- ----------- --------- ------------ ---------
Exercisable at 31 December 422,981 0.16 449,912 0.15
--------------------------- ----------- --------- ------------ ---------
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.
Any contingent consideration included in the consideration
payable for an asset acquisition is recorded at fair value at the
date of acquisition and included in the initial measurement of
cost. Subsequent measurement changes relating to the variable
consideration are capitalised as part of the asset value if it is
probable that future economic benefits associated with the asset
will flow to the Group and can be measured reliably.
Magnus
Magnus decommissioning-linked Golden
75% liability Eagle Total
$'000 $'000 $'000 $'000
------------------------------------- --------- ----------------------------- ------- ---------
At 31 December 2020 507,660 14,601 - 522,261
------------------------------------- --------- ----------------------------- ------- ---------
Additions - - 44,668 44,668
------------------------------------- --------- ----------------------------- ------- ---------
Change in fair value (see note 5(d)) (145,273) 5,194 - (140,079)
------------------------------------- --------- ----------------------------- ------- ---------
Unwinding of discount (see note 6) 50,766 1,460 507 52,733
------------------------------------- --------- ----------------------------- ------- ---------
Interest on vendor loan (see note 6) 6,169 - - 6,169
------------------------------------- --------- ----------------------------- ------- ---------
Utilisation (74,695) (279) - (74,974)
------------------------------------- --------- ----------------------------- ------- ---------
At 31 December 2021 344,627 20,976 45,175 410,778
------------------------------------- --------- ----------------------------- ------- ---------
Classified as:
------------------------------------- --------- ----------------------------- ------- ---------
Current 26,225 4,252 - 30,477
------------------------------------- --------- ----------------------------- ------- ---------
Non-current 318,402 16,724 45,175 380,301
------------------------------------- --------- ----------------------------- ------- ---------
344,627 20,976 45,175 410,778
------------------------------------- --------- ----------------------------- ------- ---------
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 financed by BP was fully settled in June 2021. 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. Oil price assumptions and discount rate assumptions used
were as disclosed in Use of judgements, estimates and assumptions
within note 2. The contingent consideration was fair valued at 31
December 2021, which resulted in a decrease in fair value of $145.3
million (2020: decrease of $137.4 million). The decrease in fair
value in 2021 is a result of revised operating cost assumptions.
The decrease in 2020 reflected the change in oil price assumptions.
The fair value accounting effect and finance costs of $57.0 million
(2020: $77.3 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 2021 in the present value
calculations (2020: cap was not met). Within the statement of cash
flows the profit share element of the repayment, $1.0 million
(2020: $41.1 million), is disclosed separately under investing
activities; the repayment of the vendor loan, $73.7 million (2020:
$20.7 million), is disclosed under financing activities; and the
interest paid on the vendor loan, $6.2 million (2020: $10.3
million), is included within interest paid under financing
activities. As part of the Golden Eagle area transaction, the
repayment of the vendor loan was completed in July 2021. At 31
December 2021, the contingent consideration for Magnus was $344.6
million (31 December 2020: $507.7 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 the 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 $85.1
million or an increase of $85.1 million to the contingent
consideration, respectively (2020: reduction of $91.7 million and
increase of $91.7 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 2021, 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 2021, the amount
due to BP calculated on an after-tax basis by reference to 30% of
BP's decommissioning costs on Magnus was $21.0 million (2020: $14.6
million).
Golden Eagle contingent consideration
On 22 October 2021, the Group completed the acquisition of the
entire 26.69% non-operated working interest in the Golden Eagle
Area Development, comprising the producing Golden Eagle, Peregrine
and Solitaire fields (see note 10). The consideration for the
acquisition included an amount that was contingent on the average
oil price between July 2021 and June 2023. 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 $25.0 million is payable, or if the
Dated Brent average crude price equals or exceeds $65/bbl, upon
which $50.0 million is payable. The contingent consideration
liability is discounted at 7% and is calculated principally based
on the oil price assumptions as disclosed in note 2. At 31 December
2021, the contingent consideration was valued at $45.2 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 for producing assets. For assets that have ceased
production, the change in estimate is reflected as an adjustment to
the provision and the Group Income Statement, via other income or
expense. 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 believes 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 Use of
judgements, estimates and assumptions: provisions within 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 2020 778,204 53,066 9,137 840,407
-------------------------- --------------- ---------------- ----------- --------
Additions during the year 119,312 - 13,390 132,702
-------------------------- --------------- ---------------- ----------- --------
Changes in estimates (22,059) 6,184 (264) (16,139)
-------------------------- --------------- ---------------- ----------- --------
Unwinding of discount 15,856 1,061 - 16,917
-------------------------- --------------- ---------------- ----------- --------
Utilisation (55,594) (16,553) (6,970) (79,117)
-------------------------- --------------- ---------------- ----------- --------
Foreign exchange 2 172 (2) 172
-------------------------- --------------- ---------------- ----------- --------
At 31 December 2021 835,721 43,930 15,291 894,942
-------------------------- --------------- ---------------- ----------- --------
Classified as:
-------------------------- --------------- ---------------- ----------- --------
Current 116,229 9,156 15,291 140,676
-------------------------- --------------- ---------------- ----------- --------
Non-current 719,492 34,774 - 754,266
-------------------------- --------------- ---------------- ----------- --------
835,721 43,930 15,291 894,942
-------------------------- --------------- ---------------- ----------- --------
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. Additions
during the year relate to the decommissioning provision recognised
as part of the Golden Eagle acquisition. At 31 December 2021, an
estimated $409.6 million is expected to be utilised between one and
five years (2020: $329.2 million), $81.4 million within six to ten
years (2020: $145.1 million), and the remainder in later
periods.
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 2021, the Group held surety bonds
totalling $240.8 million (2020: $151.7 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 2021, the amount due to BP by reference to 7.5% of BP's
decommissioning costs on Thistle and Deveron was $43.9 million
(2020: $53.1 million). Unwinding of discount of $1.1 million is
included within finance income for the year ended 31 December 2021
(2020: $0.8 million).
Other provisions
During 2020, a riser at the Seligi Alpha platform which provides
gas lift and injection to the Seligi Bravo platform detached. A
provision with respect to required repairs to remedy the damage
caused was established. During 2021, $4.4 million was utilised and
at 31 December 2021, the provision was $1.5 million (31 December
2020: $5.9 million).
During 2021, the Group recognised $8.2 million in relation to
disputes with third-party contractors. The Group expects the
dispute to be settled in 2022.
Other provisions from 31 December 2020 were fully utilised in
the year. These included a redundancy provision in relation to the
transformation programme undertaken during 2020/2021 (31 December
2020: $1.2 million) and payment of partners' share of pipeline oil
stock following cessation of production at Heather (31 December
2020: $1.5 million).
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.
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 2019 685,199 716,166
-------------------------------------- ------------ ------------
Additions in the period 2,812 2,812
-------------------------------------- ------------ ------------
Depreciation expense (82,703) -
-------------------------------------- ------------ ------------
Impairment (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
-------------------------------------- ------------ ------------
Additions in the period (see note 10) 17,815 17,815
-------------------------------------- ------------ ------------
Depreciation expense (see note 10) (63,953) -
-------------------------------------- ------------ ------------
Impairment reversal (see note 10) 15,669 -
-------------------------------------- ------------ ------------
Disposal (2,580) (3,121)
-------------------------------------- ------------ ------------
Interest expense - 45,359
-------------------------------------- ------------ ------------
Payments - (136,651)
-------------------------------------- ------------ ------------
Foreign exchange movements - (467)
-------------------------------------- ------------ ------------
As at 31 December 2021 463,393 570,781
-------------------------------------- ------------ ------------
Current 128,281
-------------------------------------- ------------ ------------
Non-current 442,500
-------------------------------------- ------------ ------------
570,781
-------------------------------------- ------------ ------------
The Group leases assets including the Kraken FPSO, property and
oil and gas vessels, with a weighted average lease term of five
years. The maturity analysis of lease liabilities is disclosed in
note 27.
Amounts recognised in profit or loss
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
-------------------------------------------- ------------ ------------
Depreciation expense of right-of-use assets 63,953 82,703
-------------------------------------------- ------------ ------------
Interest expense on lease liabilities 45,359 50,851
-------------------------------------------- ------------ ------------
Rent expense - short-term leases 1,028 12,736
-------------------------------------------- ------------ ------------
Rent expense - leases of low-value assets 5 43
-------------------------------------------- ------------ ------------
Total amounts recognised in profit or loss 110,345 146,333
-------------------------------------------- ------------ ------------
Amounts recognised in statement of cash flows
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
------------------------------ ------------ ------------
Total cash outflow for leases 136,651 123,001
------------------------------ ------------ ------------
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 2021 was $1.7 million (2020: $1.7
million).
The following table sets out a maturity analysis of lease
payments, showing the undiscounted lease payments to be received
after the reporting date:
2021 2020
$'000 $'000
---------------------------------- ------ -------
Less than one year 2,206 2,211
---------------------------------- ------ -------
One to two years 2,206 2,211
---------------------------------- ------ -------
Two to three years 2,206 2,211
---------------------------------- ------ -------
Three to four years 2,206 2,211
---------------------------------- ------ -------
Four to five years 2,206 1,508
---------------------------------- ------ -------
More than five years 1,204 1,093
---------------------------------- ------ -------
Total undiscounted lease payments 12,234 11,444
---------------------------------- ------ -------
25. Commitments and contingencies
Capital commitments
At 31 December 2021, the Group had capital commitments amounting
to $1.9 million (2020: nil).
Other commitments
In the normal course of business, the Group will obtain surety
bonds, letters of credit and guarantees. At 31 December 2021, the
Group held surety bonds totalling $240.8 million (2020: $151.7
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
Group 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 Group balance sheet or
profitability, nor, so far as the Group 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 2021 (2020: none).
Office sub-lease
During the year ended 31 December 2021, the Group recognised nil
(2020: $0.1 million) 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.
2021 2020
$'000 $'000
--------------------------------- ------ ------
Short-term employee benefits 6,890 7,576
--------------------------------- ------ ------
Share-based payments 810 107
--------------------------------- ------ ------
Post-employment pension benefits 215 224
--------------------------------- ------ ------
7,915 7,907
--------------------------------- ------ ------
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 cash equivalents,
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 2021 and 2020, 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. On a rolling quarterly basis, under
the RBL, the Group is required to hedge a minimum of 60% of volumes
of net entitlement production expected to be produced in the next
12 months, 40% of volumes of net entitlement produced expected for
following 12 months and 10% of volumes of net entitlement
production expected to be produced in the subsequent period. This
requirement ceases at the end date of the facility.
Details of the commodity derivative contracts entered into
during and open at the end of 2021 are disclosed in note 19. As of
31 December 2021, the Group held financial instruments (options and
swaps) related to crude oil that covered 8.0 MMbbls of 2022
production and 3.5 MMbbls of 2023 production. The instruments have
an effective average floor price of around $62.5/bbl in 2022 and
$57.5/bbl in 2023. 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
2021.
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 2021 (91,755) 55,267
----------------- --------- ---------
31 December 2020 (8,020) 1,365
----------------- --------- ---------
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 18%
(2020: 8%) of the Group's sales and 89% (2020: 86%) 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 2021 $'000 $'000 $'000 $'000
---------------------------- ------- ------ ------ -------
Total financial assets 103,253 34,255 3,967 141,475
------------------------------ ------- ------ ------ -------
Total financial liabilities 635,840 21,058 839 657,737
------------------------------ ------- ------ ------ -------
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
------------------------------ ------- ------ ------ -------
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 rate
increase decrease
$'000 $'000
----------------- --------- ---------
31 December 2021 (50,695) 50,695
----------------- --------- ---------
31 December 2020 (46,183) 46,183
----------------- --------- ---------
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 2021 there were $0.2 million of trade receivables past due
(2020: $2.6 million) and nil of joint venture receivables past due
(2020: $2.5 million) but not impaired. Subsequent to the year end,
$0.1 million of these outstanding balances have been collected
(2020: $4.4 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.
2021 2020
Ageing of past due but not impaired receivables $'000 $'000
------------------------------------------------ ------ ------
Less than 30 days - 2,974
------------------------------------------------ ------ ------
30-60 days 30 1,335
------------------------------------------------ ------ ------
60-90 days 146 164
------------------------------------------------ ------ ------
90-120 days - 271
------------------------------------------------ ------ ------
120+ days - 383
------------------------------------------------ ------ ------
176 5,127
------------------------------------------------ ------ ------
At 31 December 2021, the Group had one customer accounting for
84% of outstanding trade receivables (2020: three customers, 77%)
and one joint venture partner accounting for 20% of outstanding
joint venture receivables (2020: one joint venture partner,
16%).
Liquidity risk
The Group monitors its risk of 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 2021, $32.0 million (2020: $61.2 million) was
available for drawdown under the Group's 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 Group's liabilities, except for
the RBL, are unsecured.
Up to 1 to 2 2 to 5 Over 5
On demand 1 year years years years Total
Year ended 31 December 2021 $'000 $'000 $'000 $'000 $'000 $'000
--------------------------------- --------- -------- ---------- -------- -------- ----------
Loans and borrowings - 241,937 204,081 - - 446,018
--------------------------------- --------- -------- ---------- -------- -------- ----------
Bonds(i) - 75,862 1,162,595 - - 1,238,457
--------------------------------- --------- -------- ---------- -------- -------- ----------
Contingent considerations - 26,225 68,947 115,485 183,969 394,626
--------------------------------- --------- -------- ---------- -------- -------- ----------
Obligations under finance leases - 125,374 95,464 311,276 35,844 567,958
--------------------------------- --------- -------- ---------- -------- -------- ----------
Trade and other payables - 420,543 - - - 420,543
--------------------------------- --------- -------- ---------- -------- -------- ----------
- 889,941 1,531,087 426,761 219,813 3,067,602
--------------------------------- --------- -------- ---------- -------- -------- ----------
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 - 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
--------------------------------- --------- -------- -------- ---------- -------- ----------
(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 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 2021 $'000 $'000 $'000 $'000 $'000 $'000
------------------------------- --------- --------- ------- ------ ------ ------
Commodity derivative contracts 4,450 17,288 24,035 15,746 - 61,519
4,450 17,288 24,035 15,746 - 61,519
------------------------------- --------- --------- ------- ------ ------ ------
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
------------------------------- --------- --------- ------- ------ ------ ------
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 external risks,
see Commodity price risk - oil prices and Foreign exchange risk.
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
2021 restated
$'000 $'000
---------------------------------------------------------- --------- ----------
Loans, borrowings and bond(i) (A) (see note 18) 1,508,604 1,502,564
---------------------------------------------------------- --------- ----------
Cash and short-term deposits (see note 14) (286,661) (222,830)
---------------------------------------------------------- --------- ----------
Net debt (B) 1,221,943 1,279,734
---------------------------------------------------------- --------- ----------
Equity attributable to EnQuest PLC shareholders (C) 543,766 (207,377)
---------------------------------------------------------- --------- ----------
Profit/(loss) for the year attributable to EnQuest PLC
shareholders (D) 376,988 (469,927)
---------------------------------------------------------- --------- ----------
Profit/(loss) for the year attributable to EnQuest PLC
shareholders excluding exceptionals (E) 220,284 (26,187)
---------------------------------------------------------- --------- ----------
Adjusted EBITDA (F) 742,868 550,606
---------------------------------------------------------- --------- ----------
Gross gearing ratio (A/C) 2.8 n/a
---------------------------------------------------------- --------- ----------
Net gearing ratio (B/C) 2.2 n/a
---------------------------------------------------------- --------- ----------
Net debt/Adjusted EBITDA (B/F) 1.6 2.3
---------------------------------------------------------- --------- ----------
Shareholders' return on investment (D/C) 74% n/a
---------------------------------------------------------- --------- ----------
Shareholders' return on investment excluding exceptionals 41%
(E/C) n/a
---------------------------------------------------------- --------- ----------
(i) Principal amounts drawn, excludes netting off of fees (see note 18)
28. Subsidiaries
At 31 December 2021, 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 Limited1 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%
---------------------------------- ---------------------------------------- ------------- -----------
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) Limited2 of an oil pipeline Scotland 100%
---------------------------------- ---------------------------------------- ------------- -----------
Provision of Group manpower and
EnQuest Global Services contracting/procurement services
Limited(i)3 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)4 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%
---------------------------------- ---------------------------------------- ------------- -----------
Exploration, extraction and production
EnQuest Progress Limited(i) of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
North Sea (Golden Eagle) Exploration, extraction and production
Resources Ltd of hydrocarbons England 100%
---------------------------------- ---------------------------------------- ------------- -----------
(i) Held by subsidiary undertaking
The Group has two branches outside the UK (all held by
subsidiary undertakings): EnQuest Global Services Limited (Dubai)
and EnQuest Petroleum Production Malaysia Limited (Malaysia).
Registered office addresses:
1 Suite 2200, 1055 West Hastings Street, Vancouver, British Columbia, V6E 2E9
2 Annan House, Palmerston Road, Aberdeen, Scotland, AB11 5QP, United Kingdom
3 Ground Floor, Colomberie House, St Helier, JE4 0RX, Jersey
4 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
2021 restated(i)
Notes $'000 $'000
---------------------------------------------------------- ----- ------------ ------------
Profit/(loss) before tax 352,441 (565,975)
---------------------------------------------------------- ----- ------------ ------------
Depreciation 5(c) 7,492 7,616
---------------------------------------------------------- ----- ------------ ------------
Depletion 5(b) 305,578 438,247
---------------------------------------------------------- ----- ------------ ------------
Net impairment (reversal)/charge to oil and gas
assets 4 (39,715) 422,495
---------------------------------------------------------- ----- ------------ ------------
Write down of inventory 151 24,940
---------------------------------------------------------- ----- ------------ ------------
Change in fair value of investments 1 4
---------------------------------------------------------- ----- ------------ ------------
Share-based payment charge 5(f) 6,351 3,401
---------------------------------------------------------- ----- ------------ ------------
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 Magnus related contingent consideration 22 (81,684) (60,991)
---------------------------------------------------------- ----- ------------ ------------
Change in provisions 23 16,900 119,642
---------------------------------------------------------- ----- ------------ ------------
Other non-cash income 5(d) (22,568) -
---------------------------------------------------------- ----- ------------ ------------
Other expense on final settlement relating to the
Magnus acquisition 5(e) 3,832 -
---------------------------------------------------------- ----- ------------ ------------
Change in Golden Eagle related contingent consideration 22 507 -
---------------------------------------------------------- ----- ------------ ------------
Option premiums 19 1,030 (6,226)
---------------------------------------------------------- ----- ------------ ------------
Unrealised (gain)/loss on commodity financial instruments 5(a) 54,451 (8,778)
---------------------------------------------------------- ----- ------------ ------------
Unrealised (gain)/loss on other financial instruments 5(b) (472) 1,932
---------------------------------------------------------- ----- ------------ ------------
Unrealised exchange loss/(gain) (425) 5,067
---------------------------------------------------------- ----- ------------ ------------
Net finance expense 152,306 163,339
---------------------------------------------------------- ----- ------------ ------------
Operating profit before working capital changes 756,176 535,460
---------------------------------------------------------- ----- ------------ ------------
Decrease/(increase) in trade and other receivables (171,946) 184,560
---------------------------------------------------------- ----- ------------ ------------
(Increase)/decrease in inventories (13,496) (5,438)
---------------------------------------------------------- ----- ------------ ------------
(Decrease)/increase in trade and other payables 186,194 (147,417)
---------------------------------------------------------- ----- ------------ ------------
Cash generated from operations 756,928 567,165
---------------------------------------------------------- ----- ------------ ------------
(i) 2020 comparative restated. See note 2 Basis of preparation - Restatements
Changes in liabilities arising from financing activities
Loans and
borrowings Bonds Lease liabilities Total
$'000 $'000 $'000 $'000
---------------------------------------------- ----------- ----------- ----------------- -----------
At 1 January 2020 (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)
---------------------------------------------- ----------- ----------- ----------------- -----------
Cash movements:
---------------------------------------------- ----------- ----------- ----------------- -----------
Repayments of loans and borrowings 184,276 - - 184,276
---------------------------------------------- ----------- ----------- ----------------- -----------
Drawdowns of loans and borrowings (125,000) - - (125,000)
---------------------------------------------- ----------- ----------- ----------------- -----------
Repayment of lease liabilities - - 136,651 136,651
---------------------------------------------- ----------- ----------- ----------------- -----------
Cash interest paid in year 19,428 38,154 - 57,582
---------------------------------------------- ----------- ----------- ----------------- -----------
Non-cash movements:
---------------------------------------------- ----------- ----------- ----------------- -----------
Additions 2,082 - (17,815) (15,733)
---------------------------------------------- ----------- ----------- ----------------- -----------
Interest/finance charge payable (20,206) (69,085) (45,359) (134,650)
---------------------------------------------- ----------- ----------- ----------------- -----------
Fee amortisation (9,857) (1,173) - (11,030)
---------------------------------------------- ----------- ----------- ----------------- -----------
Disposal - - 3,121 3,121
---------------------------------------------- ----------- ----------- ----------------- -----------
Foreign exchange and other non-cash movements (14) 1,876 467 2,329
---------------------------------------------- ----------- ----------- ----------------- -----------
At 31 December 2021 (402,065) (1,109,920) (570,781) (2,082,766)
---------------------------------------------- ----------- ----------- ----------------- -----------
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)
--------------------------- ----------- ----------- ----------------- -----------
Principal (424,864) (1,083,740) (570,781) (2,079,385)
Unamortised fees 23,250 2,144 - 25,394
Accrued interest (note 17) (451) (28,324) - (28,775)
--------------------------- ----------- ----------- ----------------- -----------
At 31 December 2021 (402,065) (1,109,920) (570,781) (2,082,766)
--------------------------- ----------- ----------- ----------------- -----------
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.
The use of the business performance APM is explained in note 2
of the Group's consolidated financial statements on page 32.
2020
2021 restated
Business performance net profit attributable to EnQuest PLC
shareholders $'000 $'000
------------------------------------------------------------- -------- ---------
Reported net profit/(loss) (A) 376,988 (469,945)
------------------------------------------------------------- -------- ---------
Adjustments - remeasurements and exceptional items (note
4):
------------------------------------------------------------- -------- ---------
Unrealised (losses)/gains on derivative contracts (note 19) (53,979) 6,846
------------------------------------------------------------- -------- ---------
Net impairment (charge)/reversal to oil and gas assets (note
10, note 11 and note 12) 39,715 (422,495)
------------------------------------------------------------- -------- ---------
Finance costs on Magnus contingent consideration (note 6) (58,395) (77,259)
------------------------------------------------------------- -------- ---------
Change in Magnus contingent consideration (note 5(d)) 140,079 138,249
------------------------------------------------------------- -------- ---------
Movement in other provisions (7,673) (11,694)
------------------------------------------------------------- -------- ---------
Loss on derecognition of assets related to the Seligi riser
detachment (note 5(e)) - (956)
------------------------------------------------------------- -------- ---------
Other exceptional income (note 5(d)) 22,568 -
------------------------------------------------------------- -------- ---------
Other exceptional expenses (note 5(e)) (3,832) -
------------------------------------------------------------- -------- ---------
Pre-tax remeasurements and exceptional items (B) 78,483 (367,309)
------------------------------------------------------------- -------- ---------
Tax on remeasurements and exceptional items (C) 78,221 (76,449)
------------------------------------------------------------- -------- ---------
Post-tax remeasurements and exceptional items (D = B + C) 156,704 (443,758)
------------------------------------------------------------- -------- ---------
Business performance net profit attributable to EnQuest PLC
shareholders (A - D) 220,284 (26,187)
------------------------------------------------------------- -------- ---------
Adjusted EBITDA is a measure of profitability. It provides a
metric to show earnings before the influence of accounting (i.e.
depletion and depreciation) and financial deductions (i.e.
borrowing interest). For the Group, this is a useful metric as a
measure to evaluate the Group's underlying operating performance
and is a component of a covenant measure under the Group's RBL
facility. It is commonly used by stakeholders as a comparable
metric of core profitability and can be used as an indicator of
cash flows available to pay down debt. Due to the adjustment made
to reach adjusted EBITDA, the Group notes the metric should not be
used in isolation. The nearest equivalent measure on an IFRS basis
is profit or loss before interest and tax.
2021 2020
Adjusted EBITDA $'000 $'000
-------------------------------------------------------------- --------- ---------
Reported profit/(loss) from operations before tax and finance
income/(costs) 580,059 (310,069)
-------------------------------------------------------------- --------- ---------
Adjustments:
-------------------------------------------------------------- --------- ---------
Remeasurements and exceptional items (note 4) (136,878) 290,050
-------------------------------------------------------------- --------- ---------
Depletion and depreciation (note 5(b) and note 5(c)) 313,070 445,863
-------------------------------------------------------------- --------- ---------
Inventory revaluation 151 24,940
-------------------------------------------------------------- --------- ---------
Change in provision (note 5(d) and note 5(e)) (13,143) 95,197
-------------------------------------------------------------- --------- ---------
Net foreign exchange (gain)/loss (note 5(d) and note 5(e)) (391) 4,625
-------------------------------------------------------------- --------- ---------
Adjusted EBITDA (E) 742,868 550,606
-------------------------------------------------------------- --------- ---------
Total cash and available facilities is a measure of the Group's
liquidity at the end of the reporting period. The Group believes
this is a useful metric as it is an important reference point for
the Group's going concern and viability assessments, see pages 14
to 16.
2021 2020
Total cash and available facilities $'000 $'000
---------------------------------------------- --------- ---------
Available cash 276,970 221,155
---------------------------------------------- --------- ---------
Restricted cash 9,691 1,675
---------------------------------------------- --------- ---------
Total cash and cash equivalents (F) (note 14) 286,661 222,830
---------------------------------------------- --------- ---------
Available credit facilities 500,000 450,000
---------------------------------------------- --------- ---------
Credit facility - drawn down (415,000) (360,000)
---------------------------------------------- --------- ---------
Letter of credit (note 18) (53,000) (28,778)
---------------------------------------------- --------- ---------
Available undrawn facility (G) 32,000 61,222
---------------------------------------------- --------- ---------
Total cash and available facilities (F + G) 318,661 284,052
---------------------------------------------- --------- ---------
Net debt is a liquidity measure that shows how much debt a
company has on its balance sheet compared to its cash and cash
equivalents. With de-leveraging a strategic priority, the Group
believes this is a useful metric to demonstrate progress in this
regard. It is also an important reference point for the Group's
going concern and viability assessments, see pages 14 to 16.
2021 2020
Net debt $'000 $'000
---------------------------------------------- --------- ----------
Borrowings (note 18):
---------------------------------------------- --------- ----------
RBL 391,750 -
---------------------------------------------- --------- ----------
Credit facility - 377,270
---------------------------------------------- --------- ----------
Sculptor Capital facility - 65,776
---------------------------------------------- --------- ----------
SVT working capital facility 9,864 9,238
---------------------------------------------- --------- ----------
Borrowings (H) 401,614 452,284
---------------------------------------------- --------- ----------
Bonds (note 18):
---------------------------------------------- --------- ----------
High yield bond 825,441 796,528
---------------------------------------------- --------- ----------
Retail bond 256,155 248,513
---------------------------------------------- --------- ----------
Bonds (I) 1,081,596 1,045,041
---------------------------------------------- --------- ----------
Non-cash accounting adjustments (note 18):
---------------------------------------------- --------- ----------
Unamortised fees on loans and borrowings 23,250 1,925
---------------------------------------------- --------- ----------
Unamortised fees on bonds 2,144 3,314
---------------------------------------------- --------- ----------
Non-cash accounting adjustments (J) 25,394 5,239
---------------------------------------------- --------- ----------
Debt (H + I + J) (K) 1,508,604 1,502,564
---------------------------------------------- --------- ----------
Less: Cash and cash equivalents (note 14) (E) 286,661 222,830
---------------------------------------------- --------- ----------
Net debt/(cash) (K - F) (L) 1,221,943 1,279,734
---------------------------------------------- --------- ----------
The Net debt/Adjusted EBITDA metric is a ratio that provides
management and users of the Group's Consolidated financial
statements with an indication of how many years it would take to
service the Group's debt. This is a helpful metric to monitor the
Group's progress against its strategic objective of
de-leveraging.
2021 2020
Net debt/Adjusted EBITDA $'000 $'000
------------------------------- --------- ----------
Net debt (L) 1,221,943 1,279,734
------------------------------- --------- ----------
Adjusted EBITDA (E) 742,868 550,606
------------------------------- --------- ----------
Net debt/Adjusted EBITDA (L/E) 1.6 2.3
------------------------------- --------- ----------
Cash capex monitors investing activities on a cash basis, while
cash abandonment monitors the Group's cash spend on investing and
decommissioning activities. The Group provides guidance to the
financial markets for both these metrics given the focus on the
Group's liquidity position and ability to reduce its debt.
2021 2020
Cash capex and Cash capital and abandonment expense $'000 $'000
------------------------------------------------------------------------ --------- ---------
Reported net cash flows (used in)/from investing activities (321,230) (120,597)
------------------------------------------------------------------------ --------- ---------
Adjustments:
------------------------------------------------------------------------ --------- ---------
Purchase of other intangible assets 10,052 -
------------------------------------------------------------------------ --------- ---------
Repayment of Magnus contingent consideration - Profit share 968 41,071
------------------------------------------------------------------------ --------- ---------
Net cash received on termination of Tanjong Baram risk service contract - (51,054)
------------------------------------------------------------------------ --------- ---------
Acquisition costs 258,627 -
------------------------------------------------------------------------ --------- ---------
Interest received (256) (796)
------------------------------------------------------------------------ --------- ---------
Cash capex (51,839) (131,376)
------------------------------------------------------------------------ --------- ---------
Decommissioning spend (65,791) (41,605)
------------------------------------------------------------------------ --------- ---------
Cash capital and abandonment expense (117,630) (172,981)
------------------------------------------------------------------------ --------- ---------
Free cash flow ('FCF') represents the cash a company generates,
after accounting for cash outflows to support operations, to
maintain its capital assets. Currently this metric is useful to
management and users to assess the Group's ability to reduce its
debt.
During 2021, the Group updated the definition of FCF to adjust
for the impact of share issues and acquisitions. The definition of
free cash flow is now net cash flow adjusted for net
repayment/proceeds of loans and borrowings, net proceeds of share
issues and cost of acquisitions.
In 2021, the Group made an accelerated repayment of the Magnus
Vendor loan of $58.7 million. As the repayment was made out of
Group cash flows rather than as part of the Magnus-related
waterfall mechanism, the Group has adjusted for this accelerated
repayment for the purpose of calculating FCF.
2020
2021 restated
Free cash flow $'000 $'000
-------------------------------------------------------------- --------- ---------
Net cash flows from/(used in) operating activities 674,138 521,420
-------------------------------------------------------------- --------- ---------
Net cash flows from/(used in) investing activities (321,230) (120,597)
-------------------------------------------------------------- --------- ---------
Net cash flows from/(used in) financing activities (285,474) (401,014)
-------------------------------------------------------------- --------- ---------
Adjustments:
-------------------------------------------------------------- --------- ---------
(125,000
Proceeds of loans and borrowings ) -
-------------------------------------------------------------- --------- ---------
Repayment of loans and borrowings 184,276 210,671
-------------------------------------------------------------- --------- ---------
Acquisitions 258,627 -
-------------------------------------------------------------- --------- ---------
Repayment of Magnus contingent consideration - Vendor loan(i) 58,668 -
-------------------------------------------------------------- --------- ---------
Net proceeds from share issue (47,782) -
-------------------------------------------------------------- --------- ---------
Shares purchased by Employee Benefit Trust 576 -
-------------------------------------------------------------- --------- ---------
Free cash flow 396,799 210,480
-------------------------------------------------------------- --------- ---------
(i) Related to the accelerated vendor loan repayment
2021 2020
Revenue sales $'000 $'000
---------------------------------------------------------- --------- --------
Revenue from crude oil sales (note 5(a)) (M) 1,139,171 779,865
---------------------------------------------------------- --------- --------
Revenue from gas and condensate sales (note 5(a)) (N) 244,073 60,486
---------------------------------------------------------- --------- --------
Realised (losses)/gains on oil derivative contracts (note
5(a)) (P) (67,679) (6,059)
---------------------------------------------------------- --------- --------
2021 2020
Barrels equivalent sales kboe kboe
------------------------------- ------ -------
Sales of crude oil (Q) 15,609 18,758
------------------------------- ------ -------
Sales of gas and condensate(i) 2,829 3,471
------------------------------- ------ -------
Total sales (R) 18,438 22,229
------------------------------- ------ -------
(i) Includes volumes related to onward sale of third-party gas
purchases not required for injection activities at Magnus
Average realised price is a measure of the revenue earned per
barrel sold. The Group believes this is a useful metric for
comparing performance to the market and to give the user, both
internally and externally, the ability to understand the drivers
impacting the Group's revenue.
2021 2020
Average realised prices $/Boe $/Boe
-------------------------------------------------------------- ------ ------
Average realised oil price, excluding hedging (M/Q) 73.0 41.6
-------------------------------------------------------------- ------ ------
Average realised oil price, including hedging ((M + P)/Q) 68.6 41.3
-------------------------------------------------------------- ------ ------
Average realised blended price, excluding hedging ((M + N)/R) 75.0 37.8
-------------------------------------------------------------- ------ ------
Average realised blended price, including hedging ((M + N
+ P)/R) 71.4 37.5
-------------------------------------------------------------- ------ ------
Operating costs ('opex') is a measure of the Group's cost
management performance. Opex is a key measure to monitor the
Group's alignment to its strategic pillars of financial discipline
and value enhancement and is required in order to calculate opex
per barrel (see below).
2021 2020
Operating costs $'000 $'000
------------------------------------------------------------ --------- ---------
Reported cost of sales (note 5(b)) 907,634 799,081
------------------------------------------------------------ --------- ---------
Adjustments:
------------------------------------------------------------ --------- ---------
Remeasurements and exceptional items (note 5(b)) (7,201) (13,626)
------------------------------------------------------------ --------- ---------
Depletion of oil and gas assets (note 5(b)) (305,578) (438,247)
------------------------------------------------------------ --------- ---------
(Credit)/charge relating to the Group's lifting position
and inventory (note 5(b)) (62,307) 34,801
------------------------------------------------------------ --------- ---------
Other cost of operations (note 5(b)) (211,575) (53,367)
------------------------------------------------------------ --------- ---------
Operating costs 320,973 328,642
------------------------------------------------------------ --------- ---------
Less realised (gain)/loss on derivative contracts (S) (note
5(b)) 10,693 572
------------------------------------------------------------ --------- ---------
Operating costs directly attributable to production 331,666 329,214
------------------------------------------------------------ --------- ---------
Comprising of:
------------------------------------------------------------ --------- ---------
Production costs (T) (note 5(b)) 292,252 265,529
------------------------------------------------------------ --------- ---------
Tariff and transportation expenses (U) (note 5(b)) 39,414 63,685
------------------------------------------------------------ --------- ---------
Operating costs directly attributable to production 331,666 329,214
------------------------------------------------------------ --------- ---------
2021 2020
Barrels equivalent produced kboe kboe
-------------------------------------- ------ ------
Total produced (working interest) (V) 16,211 21,636
-------------------------------------- ------ ------
Unit opex is the operating expenditure per barrel of oil
equivalent produced. This metric is useful as it is an industry
standard metric allowing comparability between oil and gas
companies. Unit opex including hedging includes the effect of
realised gains and losses on derivatives related to foreign
currency and emissions allowances. This is a useful measure for
investors because it demonstrates how the Group manages it's risk
to market price movements.
2021 2020
Unit opex $/Boe $/Boe
--------------------------------------------------- ------ ------
Production costs (T/V) 18.1 12.3
--------------------------------------------------- ------ ------
Tariff and transportation expenses (U/V) 2.4 2.9
--------------------------------------------------- ------ ------
Total unit opex ((T + U)/V) 20.5 15.2
--------------------------------------------------- ------ ------
Realised (gain)/loss on derivative contracts (S/V) (0.7) -
--------------------------------------------------- ------ ------
Total unit opex including hedging ((S + T+ U)/V) 19.8 15.2
--------------------------------------------------- ------ ------
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END
FR FFFVFVDIVFIF
(END) Dow Jones Newswires
March 24, 2022 03:01 ET (07:01 GMT)
Enquest (LSE:ENQ)
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