REG - EnQuest PLC - Results for the year ended 31 December 2021
24/03/2022 07:15
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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 £2.2 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 on a net working interest basis 1 Jan 2021 to 1 Jan 2020 to
31 Dec 2021 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 million. 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 £2.2 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
(https://onlinexperiences.com/scripts/Server.nxp?LASCmd=AI:4;F:QS!10100&ShowUUID=D8F4DE34-B756-40B5-B1BB-A0871373C594)
. 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 (http://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 2021 31 December 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 20211 (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 2021 31 December 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 £155.0 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 £190
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))
Notes Business performance Remeasurements and exceptional items (note 4) Reported in year Business performance Remeasurements and exceptional items (note 4) Reported in year
$'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 376,988 (469,945)
the parent
(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
Notes 2021 2020 restated((i))
$'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
Share capital and share premium Merger Share-based payments reserve Retained earnings Total
$'000 Reserve((i)) $'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
Notes 2021 2020
$'000 restated((i))
$'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))
2020 (as previously reported) Restatement adjustment 2020 restated
Business performance Remeasurements and exceptional items (note 4) Reported in Business performance Remeasurements and exceptional items (note 4) Reported in period
$'000 $'000 period $'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 (625,802) 155,857 (469,945)
the parent
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 reported) Restatement 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 and Disclosure of
Accounting Policies
Amendments to IAS 8
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 Financial Reporting
Standards, IFRS 9 Financial Instruments, IFRS 16 Leases, and IAS 41
IFRS Standards 2018-2020 Cycle 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.
Year ended 31 December 2021 North Sea Malaysia All other segments Total Adjustments and Consolidated
$'000 segments eliminations(i)
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
Restated Year ended 31 December 2020((iv)) North Sea Malaysia All other segments Total Adjustments and Consolidated
$'000 segments eliminations(i)
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.
Year ended 31 December 2021 Fair value Impairments Other(iii) Total
$'000 remeasurement(i) and
write-offs(ii)
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
Restated Year ended 31 December 2020 Fair value Impairments Other(iii) Total
$'000 remeasurement(i) and
write-offs(ii)
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
2021 2020
$'000 restated
$'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 2021
31 December 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 (10,693) (572)
note 19)
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 (472) 1,932
costs(iii) (see note 19)
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
2021 restated((i))
$'000 2020
$'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 847 649
Group financial statements
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
2021 2020
$'000 restated
$'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
2021 2020
$'000 restated((i))
$'000
Profit/(loss) before tax 352,441 (565,975)
UK statutory tax rate applying to North Sea oil and gas activities of 40% 140,976 (226,390)
(2020: 40%)
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:
Group balance sheet (Credit)/charge for the year recognised in profit or loss
2021 2020 2021 2020
$'000 restated((i)) $'000 restated((i))
$'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)
2021 2020
$'000 restated((i))
$'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:
Profit/(loss) after tax Weighted average number of Ordinary shares Earnings per share
Year ended 31 December Year ended 31 December Ye
ar
en
de
d
31
De
ce
mb
er
2021 2020 2021 2020 2021 2020
$'000 restated((ii)) million million $ restated((ii))
$'000 $
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 - - 24.7 15.1 - -
schemes
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 and equipment Five years
Fixtures and fittings Ten years
Right-of-use assets* Lease term
* Excludes Kraken FPSO which is depleted using the unit of
production method in accordance with the related oil and gas assets
Each asset's estimated useful life, residual value and method of depreciation
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.
Oil Office Right-of-use Total
and gas
furniture,
assets
assets
fixtures and
$'000
fittings (note 24)
$'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 amount(i)
(charge)/reversal
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 and appraisal assets UK emissions allowances Total
$'000 $'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:
31 December 2021 Notes Total Quoted prices in active markets Significant observable inputs Significant unobservable inputs
$'000 (Level 1) (Level 2) (Level 3)
$'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 2,013,531 1,017,886 - 995,645
disclosed
31 December 2020 Notes Total Quoted prices in active markets Significant observable inputs Significant unobservable inputs
$'000 (Level 1) (Level 2) (Level 3)
$'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 1,865,600 763,545 - 1,102,055
disclosed
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 £42.0
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 £155.0 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:
Year ended 31 December 2021 Revenue and Cost of sales
other operating income
Realised Unrealised Realised Unrealised
$'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
Year ended 31 December 2020 Revenue and Cost of sales
other operating income
Realised Unrealised Realised Unrealised
$'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.
Authorised, issued and fully paid Ordinary Share Share Total
shares of capital premium $'000
£0.05 each
$'000 $'000
Number
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
£0.19 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.
Share plans 2021 2020
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
Share options Number Weighted average exercise price $ Number Weighted average exercise 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 liability Total
75% $'000 Golden Eagle $'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.
Decommissioning provision Thistle decommissioning provision Other 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 £5,000. 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
$'000 liabilities
$'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.
Year ended 31 December 2021 GBP MYR Other Total
$'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
Year ended 31 December 2020 GBP MYR Other Total
$'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% rate -$10% 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.
Ageing of past due but not impaired receivables 2021 2020
$'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.
Year ended 31 December 2021 On demand Up to 1 year 1 to 2 years 2 to 5 years Over 5 years Total
$'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
Year ended 31 December 2020 On demand Up to 1 year 1 to 2 years 2 to 5 years Over 5 years Total
$'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.
Year ended 31 December 2021 On demand Less than 3 to 12 months 1 to 2 years Over 2 years Total
$'000 3 months $'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
Year ended 31 December 2020 On demand Less than 3 to 12 months 1 to 2 years Over 2 years Total
$'000 3 months $'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).
2021 2020
$'000 restated
$'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 220,284 (26,187)
exceptionals (E)
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 (E/C) 41% 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:
Name of company Principal activity Country of Proportion of
incorporation nominal value
of issued shares controlled by
the Group
EnQuest Britain Limited Intermediate holding company and provision of Group manpower and England 100%
contracting/procurement services
EnQuest Heather Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Thistle Limited(i) Exploration, extraction and production of hydrocarbons England 100%
Stratic UK (Holdings) Limited(i) Intermediate holding company England 100%
Grove Energy Limited1 Intermediate holding company Canada 100%
EnQuest ENS Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest UKCS Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Heather Leasing Limited(i) Leasing England 100%
EQ Petroleum Sabah Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Dons Leasing Limited(i) Dormant England 100%
EnQuest Energy Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Production Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Global Limited Intermediate holding company England 100%
EnQuest NWO Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EQ Petroleum Production Malaysia Limited(i) Exploration, extraction and production of hydrocarbons England 100%
NSIP (GKA) Limited2 Construction, ownership and operation of an oil pipeline Scotland 100%
EnQuest Global Services Limited(i)3 Provision of Group manpower and contracting/procurement services for the Jersey 100%
international business
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 of hydrocarbons Malaysia 100%
Malaysia SDN. BHD(i)4
EnQuest NNS Holdings Limited(i) Intermediate holding company England 100%
EnQuest NNS Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Advance Holdings Limited(i) Intermediate holding company England 100%
EnQuest Advance Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Forward Holdings Limited(i) Intermediate holding company England 100%
EnQuest Forward Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Progress Limited(i) Exploration, extraction and production of hydrocarbons England 100%
North Sea (Golden Eagle) Resources Ltd Exploration, extraction and production 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
Notes Year ended Year ended
31 December 31 December
2021 2020
$'000 restated((i))
$'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 Total
(see note 18) (see note 18) (see note 24) $'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.
Business performance net profit attributable to EnQuest PLC shareholders 2021 2020
$'000 restated
$'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 39,715 (422,495)
note 12)
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 - (956)
5(e))
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 - 220,284 (26,187)
D)
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.
Adjusted EBITDA 2021 2020
$'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.
Total cash and available facilities 2021 2020
$'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.
Net debt 2021 2020
$'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.
Net debt/Adjusted EBITDA 2021 2020
$'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.
Cash capex and Cash capital and abandonment expense 2021 2020
$'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.
Free cash flow 2021 2020
$'000 restated
$'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:
Proceeds of loans and borrowings (125,000) -
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
Revenue sales 2021 2020
$'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)
Barrels equivalent sales 2021 2020
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.
Average realised prices 2021 2020
$/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).
Operating costs 2021 2020
$'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 (62,307) 34,801
5(b))
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
Barrels equivalent produced 2021 2020
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.
Unit opex 2021 2020
$/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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