REG - EnQuest PLC - Results for the year ended 31 December 2023
28/03/2024 07:15
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RNS Number : 6690I EnQuest PLC 28 March 2024
EnQuest PLC, 28 March 2024
Results for the year ended 31 December 2023 and 2024 outlook
De-levered and positioned to deliver transformational growth
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 year ended 31
December 2022 and the Balance Sheet as at 31 December 2022. Alternative
performance measures are reconciled within the 'Glossary - Non-GAAP measures'
at the end of the Financial Statements.
EnQuest Chief Executive, Amjad Bseisu, said:
"EnQuest achieved its 2023 targets, delivering strong operational performance
across the operated portfolio and continuing to de-lever its balance sheet,
with year-end EnQuest net debt reduced to $481 million. Against the backdrop
of a challenging UK fiscal environment, EnQuest has reduced net debt by c.$1.5
billion since its peak and with significant tax assets remaining, the business
has a strong base, and successful track record of executing quick payback,
life-extending acquisitions, from which to pursue value-accretion and
production growth through M&A.
"Our top quartile operating capability, demonstrated through high production
uptimes across our operated asset portfolio, underpinned 2023 production of
43.8 Kboed, which was in line with the mid-point of guidance. This operational
excellence extends to our decommissioning activities, with 2023 seeing the
Group complete the plug and abandonment ('P&A') of 25 wells, delivering
top quartile well P&A performance across its Heather and Thistle projects
and executing another record-breaking year of northern North Sea multi-asset
well abandonments at sector-leading cost.
"We also realised value within the existing portfolio by selling a 15.0% share
of both the Bressay licence and the EnQuest Producer FPSO to RockRose Energy;
a transaction which represents an important step in moving the Bressay project
forward.
"As we further enhance our position as a key player in the energy transition,
we continue to progress our new energy and decarbonisation ambitions at the
Sullom Voe Terminal under the management of our newly established subsidiary,
Veri Energy. The award of four carbon storage licences during 2023 represented
a key milestone for our future ambitions. Work is underway to right-size the
terminal site and transform its carbon footprint, with delivery of the new
stabilisation facility and power generation projects expected to reduce future
CO(2) emissions at SVT by c.90%. We have already reduced our total UK
emissions by more than 40% from the 2018 benchmark, significantly ahead of the
UK's North Sea Transition Deal targets, while our credible net zero transition
plan was a key factor in EnQuest securing a B rating in the 2023 CDP Climate
Change Survey.
"We have set the foundations for a pivot to growth during 2024 and continue to
perform well against our full year targets, with production to 29 February
2024 averaging around 44,500 Boepd. The Group also fully paid down its RBL
facility post year-end and has further reduced net debt to $409.6 million at
the end of February 2024.
"Reflecting the strength of our core business, confidence in the opportunities
ahead and the Group's commitment to delivering shareholder returns during
2024, we have committed to deploy $15.0 million of capital in a share buyback
programme during 2024."
2023 performance
§ Statutory revenue and other income totalled $1,487.4 million (2022:
$1,853.6 million) and adjusted EBITDA totalled $824.7 million (2022: $979.1
million).
§ Against a backdrop of continued geopolitical tension, inflation and
Sterling volatility, Brent prices averaged $82.5/bbl (18.2% below 2022:
$100.8/bbl) and day ahead gas prices decreased to 98.9p/Therm (51.4% below
2022: 203.5p/Therm).
§ Group production (delivered at the mid-point of guidance) averaged 43,812
Boepd (2022: 47,259 Boepd), with high levels of asset uptime across the
portfolio and efficient execution of maintenance activities partially
offsetting natural field declines.
§ Reflecting the above drivers and cash tax timing, net operating cash flow
totalled $754.2 million, 19.0% below 2022 ($931.6 million).
§ Operating expenditure of $347.2 million was 12.4% below 2022 ($396.5
million). Unit opex declined to $21.9/boe (2022: $22.7/boe).
§ Capital investment of $152.2 million (2022: $115.8 million) was focused on
low cost, quick payback projects that enhanced production and lowered
emissions. Decommissioning expenditure totalled $58.9 million (2022: $59.0
million) and focused on well P&A.
§ Free cash flow generation(1) remained strong, totalling $300.0 million
(2022: $518.9 million).
§ Statutory reported loss after tax $30.8 million (2022: $41.2 million loss),
reflecting the impact of the UK Energy Profits Levy.
§ Group liquidity (cash and available facilities) rose to $498.8 million (31
December 2022: $348.9 million). EnQuest net debt totalled $480.9 million at 31
December 2023, a 32.9% reduction versus 2022 ($717.1 million).
§ Having delivered on the Group's strategic aims to deliver and de-lever,
EnQuest is pleased to announce its first shareholder distribution, a $15.0
million buyback that will be completed in 2024.
(1) Net change in cash and cash equivalents less acquisition costs and net
repayments/proceeds from loans and borrowing and share issues
2024 performance and guidance
§ Net Group production expected to average between 41,000 and 45,000 Boepd
(c.44,500 Boepd YTD to end-February).
§ Capital investment expected to total c.$200 million; Operating expenditure
expected to total c.$415 million; and Decommissioning expenditure expected to
total c.$70 million.
§ Investment is scaled to maintain production, maximise cash flow, drive
capital efficiency and reduce future emissions and costs.
§ At 29 February 2024, EnQuest net debt totalled $409.6 million and the Group
fully repaid the outstanding $140.0 million of its drawn reserve based lending
facility ('RBL').
Outlook - 2025 and beyond
§ Capital-efficient investment programme; targeting organic production growth
in 2025.
§ Kraken FPSO lease rate reduces by c.70% from 1 April 2025 and major
projects at SVT are expected to crystallise significant emissions and
operating cost reductions in 2026 and beyond.
Production and financial information
Macro conditions 2023 2022 Change
Brent oil price(4) ($/bbl) 82.5 100.8 -18.2%
Natural gas price(4) (GBp/Therm) 98.9 203.5 -51.4%
Business performance measures 2023 2022 Change
Production (Boepd) 43,812 47,259 -7.3%
Revenue and other operating income ($m)(1) 1,459.0 1,839.1 -20.7%
Realised oil price ($/bbl)(1,2) 81.4 88.9 -8.4%
Average unit operating costs ($/Boe)(2) 21.9 22.7 -3.5%
Adjusted EBITDA ($m)(2) 824.7 979.1 -15.8%
Cash expenditures ($m) 211.1 174.8 20.8%
Capital(2) 152.2 115.8 31.4%
Decommissioning 58.9 59.0 -0.0%
Free cash flow ($m)(2) 300.0 518.9 -42.2%
End 2023 End 2022
EnQuest net (debt)/cash ($m)(2) (480.9) (717.1) -32.9%
Statutory measures 2023 2022 Change
%
Reported revenue and other operating income ($m)(3) 1,487.4 1,853.6 -19.8%
Reported gross profit ($m) 540.7 652.9 -17.2%
Reported profit/(loss) after tax ($m) (30.8) (41.2) 25.2%
Reported basic earnings/(loss) per share (cents) (1.6) (2.2) 27.3%
Net cash flow from operating activities ($m) 754.2 931.6 -19.0%
Net increase/(decrease) in cash and cash equivalents ($m) 12.9 39.1 -67.0%
Notes:
(1) Including realised losses of $11.3 million (2022: realised losses of
$203.7 million) associated with EnQuest's oil price hedges
(2) See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP Measures' starting on page 65.
(3) Including net realised and unrealised gains of $17.2 million (2022: net
realised and unrealised losses of $189.3 million) associated with EnQuest's
oil price hedges
(4) Source is Reuters Factset
2023 performance summary
Strong production performance, a lower but relatively stable commodity price
environment and the Group's commitment to disciplined, low cost, quick payback
investment underpinned $300.0 million of free cash flow generation during 2023
(2022: $518.9 million). This enabled the Group to end the year with liquidity
of c.$0.5 billion and reduce EnQuest net debt to $480.9 million (2022: $717.1
million). At 31 December 2023, the EnQuest net debt to adjusted EBITDA ratio
was down to 0.6x, (31 December 2022: 0.7x), which shows continued progress
towards the target of 0.5x.
Production of 43,812 Boepd (2022: 47,259 Boepd) reflected improved performance
at Magnus and close to 100% production efficiency at Kraken following
transformer upgrades, with top quartile production uptime across the operated
portfolio helping to partially offset natural field declines. The Group
demonstrated its differentiated operating capability by minimising the impact
of the anomalous failure of the HSP transformers by reinstating Kraken
production efficiently and in a short-time frame.
Adjusted EBITDA, net cash flow from operating activities and free cash flow
were $824.7 million (2022: $979.1 million), $754.2 million (2022: $931.6
million) and $300.0 million (2022: $518.9 million), respectively, with the
decreases from 2022 reflecting lower production and market prices. Capital
expenditure of $152.2 million (2022: $115.8 million) primarily reflected the
Magnus, Golden Eagle and Malaysia well campaigns and Sullom Voe Terminal
projects, while cash decommissioning expenditure of $58.9 million (2022: $59.0
million) was focused on well plug and abandonment ('P&A') activities at
Heather and Thistle, with a record 25 wells being decommissioned during the
year.
Following the establishment of the New Energy business in 2021 and having
progressed three significant new energy and decarbonisation opportunities at
Sullom Voe Terminal, the Group launched Veri Energy ('Veri'), a wholly owned
subsidiary of EnQuest. Veri represents the logical next step in the strategic
evolution of EnQuest's new energy and decarbonisation ambitions, enabling the
project team to move forward with a focused management structure and the
potential to leverage financial and strategic partnerships.
In December, EnQuest announced the sale of a 15.0% equity share in the Bressay
licence and the EnQuest Producer FPSO for a total consideration of £46.0
million (c. $57.0 million). Subsequently the Group received $85.6 million for
a 15.0% farm-down of capital items identified for potential use on the Bressay
development. Through these transactions the Group has realised near-term
value, expecting to yield c.$58.0 million post-tax cash flow in 2024, and
delivered an important step in moving the Bressay project forward.
Liquidity and net debt
At 31 December 2023, EnQuest net debt was $480.9 million, down $236.2 million
from $717.1 million at 31 December 2022. During the year, EnQuest repaid the
Group's £111.3 million Sterling retail bond at maturity and put in place a
term loan facility of up to $150.0 million. Following these steps, all the
Group's debt maturities are now aligned in 2027.
At 31 December 2023, cash drawings under the reserve based lending ('RBL')
facility were $140.0 million against an original commitment of $500.0 million,
while total cash and available facilities were $498.8 million (2022: $348.9
million) (including restricted funds and ring-fenced funds held in joint
venture operational accounts totalling $172.7 million (2022: $174.3 million)).
EnQuest net debt as at 29 February 2024 was further reduced to $409.6 million,
with cash and available facilities of $479.7 million. The Group also fully
repaid the $140.0 million outstanding balance on the RBL facility during
February 2024, reducing cash drawn to zero.
EnQuest remains focused on its strong balance sheet and its ongoing
deleveraging strategy. From a position of balance sheet strength, EnQuest is
pleased to announce the first shareholder distribution since its inception, a
$15.0 million buyback that will be completed in 2024.
Reserves and resources
Net 2P reserves at the end of 2024 were c.175 MMboe (2022: c.190 MMboe).
During the year, the Group produced c.16 MMboe (2022: c.17 MMboe). This
reduction was partially offset by transfers from 2C resources at Magnus, net
of other technical revisions. Net 2C resources were c.389 MMboe (2022: c.393
MMboe), with the decrease a result of progression to 2P reserves at Magnus, as
noted above.
Environmental, Social and Governance
The health, safety and wellbeing of our employees remains our top priority. In
2023, EnQuest achieved Lost Time Incident ('LTI') frequency(1) rate of 0.52
(2022: 0.57). Whilst this was an improvement versus 2022, the Group will not
be complacent as it strives to deliver SAFE results with no harm to our
people.
(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)
The Group has continued to make excellent progress in reducing its absolute
Scope 1 and 2 emissions, with CO(2) equivalent emissions reduced by c.23%
since 2020, reflecting lower flaring and lower fuel gas and diesel usage.
Since 2018, UK Scope 1 and 2 emissions have reduced by c.41%, which is
significantly ahead of the UK Government's North Sea Transition Deal target of
achieving a 10% reduction in Scope 1 and Scope 2 CO(2) equivalent emissions by
2025 and close to the 50% reduction targeted by 2030.
In recognition of progress to date in terms of emissions reduction and the
Group's credible forward plans to deliver decarbonisation and new energy
projects on the journey towards net zero by 2040, EnQuest is proud to have
secured a B rating from the prestigious CDP Climate Change Survey.
EnQuest's 2024 strategic focus is to deliver a step-change in operational
growth, diversification and carbon reduction, around which the Group has
repositioned both its Board and Senior Management.
In the year, Salman Malik (previously Chief Financial Officer ('CFO') and
Managing Director, Infrastructure and New Energy) has assumed the role of
Chief Executive Officer of Veri Energy. One of the outcomes of his appointment
as Veri CEO is that he will step down as a Director of EnQuest at the 2024
Annual General Meeting ('AGM'). In a refresh of the leadership team, Jonathan
Copus was appointed EnQuest CFO and will be proposed for election to the Board
at the AGM, while Steve Bowyer has joined EnQuest as North Sea General
Manager.
Also, during 2023, our three longest serving Non-Executive Directors, Carl
Hughes, Howard Paver, and John Winterman, stepped down from the Board at the
2023 Annual General Meeting ('AGM').
Subsequently, the Governance and Nomination Committee carried out a
comprehensive search for independent Non-Executive Directors to join the
Board, resulting in the appointment of Michael Borrell and Karina Litvack.
Unfortunately, in December, Karina had to step down from the Board due to an
unexpected conflict arising through the EU Unbundling Directive, which
prohibits any director of a European power transmission company from also
serving on the board of an upstream operator. As such, and as announced
separately this morning, we intend to appoint Rosalind Kainyah to the Board at
the Company's 2024 AGM.
Separately, both Liv Monica Stubholt and Rani Koya have advised that they will
be stepping down at the Company's 2024 AGM. Liv Monica has served on the Board
for a full three-year term and has opted to focus on her Norwegian portfolio,
and Rani has advised of a need to focus on other work priorities.
At the end of 2023, the Group's Board membership was in line with the Women
Leaders Review target of 40% female representation and work continues
throughout the organisation to deliver on our diversity and inclusion targets.
The Board currently has 43% female representation and remains ahead of the
Parker Review target with respect to minority ethnic representation, with four
minority ethnic Board members.
2024 performance and guidance
Group net production averaged around 44,500 Boepd to the end of February. For
the full year, the Group's net production is expected to be between 41,000 and
45,000 Boepd, reflecting the drilling campaigns at Magnus, PM8/Seligi and
Golden Eagle. Planned maintenance activities include two ten-day periods of
single train operations at Kraken, with 21-day and ten-day shutdowns at each
of Magnus and GKA, respectively.
Operating expenditures are expected to be approximately $415.0 million, with
the increase from 2023 largely due to phasing of activities at Magnus and SVT
and inflationary pressures.
Cash capital expenditure is expected to be around $200.0 million. The Group
plans to execute a two-well drilling campaign at Magnus in the second half of
the year, following the five-yearly rig recertification, and expects to
complete the ongoing drilling campaign at Golden Eagle, where two further HDJU
wells are planned. EnQuest's Midstream team is progressing two major
right-sizing projects at SVT, which together are expected to reduce terminal
emissions by c.90%.
Decommissioning expenditure is expected to total approximately $70.0 million,
primarily reflecting the final full year of well P&A decommissioning
programmes at the Heather/Broom and Thistle/Deveron fields and preparations
for removal of the topsides production facilities. This work will be completed
by EnQuest's dedicated in-house team which, per North Sea Transition Authority
review data, has delivered a probabilistic average cost per well for P&A
of c.£2.5 million, versus an industry benchmark of c.£4.3 million.
From 1 April 2024, EnQuest has hedged c.5.0 MMbbls of oil, with 4.1 MMbbls
hedged through the use of put options with an average floor price of c.$60/bbl
and 0.9 MMbbls through swaps at an average price of c.$86/bbl. The Group has
hedged a total of c.1.6 MMbbls for 2025 using put options at an average floor
price of c. $60/bbl.
Outlook - 2025 and beyond
The Group's 2024 capital-efficient investment programme targets organic
production growth in 2025. From 1 April 2025, the Kraken FPSO lease rate
reduces by c. 70% and major projects at SVT are expected to crystallise
significant operating cost and emission reductions in 2026 and beyond.
Summary financial review of 2023
(all figures quoted are in US Dollars and relate to Business performance
unless otherwise stated)
Overview
Strong free cash flow generation in the period of $300.0 million (2022: $518.9
million) drove a reduction in EnQuest net debt of 32.9%, to $480.9 million (31
Dec 2022: $717.1 million). At 31 December 2023, the Group's leverage ratio was
0.6x, close to its target of 0.5x, while cash and available facilities had
increased to $498.8 million (2022: $348.9 million) with all debt now maturing
in 2027.
During December, EnQuest announced the sale of a 15.0% equity share in the
Bressay licence and the EnQuest Producer FPSO for a total consideration of
£46.0 million (c. $57.0 million). Subsequently, the Group received $85.6
million for a 15.0% farm-down of capital items identified as suitable for use
on the Bressay development. Through these transactions the Group has realised
near-term value, expecting to yield c. $58.0 million post-tax cash flow in
2024, and delivered an important step in moving the project forward.
The Group's improved balance sheet, liquidity position and significantly
advantaged tax position means EnQuest is well placed to pursue growth
opportunities and the Group's Board has sanctioned the Company's first
programme of shareholder returns - committing to a $15.0 million buy back that
will be completed during 2024.
Income statement
Revenue
Brent prices in the period averaged $82.5/bbl (18.2% below 2022: $100.8/bbl)
and the average day ahead gas price decreased to 98.9p/Therm (51.4% below
2022: 203.5p/Therm). Pre-hedging, the average oil price realised by EnQuest
was $82.2/bbl (19.9% below 2022: $102.6/bbl). Post-hedging, realised oil
prices averaged $81.4/bbl, narrowing the discount year-on-year to 8.4%
($88.9/bbl).
Reflecting these drivers, reported revenue totalled $1,487.4 million, a 19.8 %
decline on 2022 ($1,853.6 million). Within this figure, oil sales accounted
for $1,127.4 million, 25.7% below 2022 ($1,517.7 million).
Realised losses on commodity hedges totalled $11.3 million (2022: losses of
$203.7 million). Unrealised gains on these contracts (mark-to-market
movements) totalled $28.5 million (2022: unrealised gains of $14.5 million).
Revenue from the sale of condensate and gas, totalling $339.0 million (2022:
$514.2 million), primarily relates to the onward sale of third-party gas that
was not required for injection activities at Magnus. The contribution from
these volumes is offset by related costs in cost of sales. Tariffs and other
income generated a further $3.8 million (2022: $11.0 million), including
income from the transportation of Seligi Associated gas.
Cost of sales
The Group demonstrated effective cost control to mitigate the effects of
underlying inflationary pressures and the volatile Sterling to US Dollar
exchange rate, noting c.83% of Group operating costs are denominated in
Sterling.
Group operating expenditures of $347.2 million were 12.4% lower than in 2022
($396.5 million), with unit operating costs (excluding foreign exchange
hedging) decreasing to $21.9/Boe (2022: $22.7/Boe). The reduction in operating
costs was driven by work programme optimisation across the portfolio, along
with higher lease charter credits and lower diesel costs at Kraken.
Other costs of operations of $305.9 million were significantly lower than in
2022 ($487.8 million), driven predominantly by lower gas prices impacting the
cost of Magnus-related third-party gas purchases which are sold on of $294.0
million (2022: $452.8 million).
Depletion expense of $292.2 million was 10.6% lower than in 2022 ($327.0
million), mainly reflecting the impact of lower production.
Impairment
In the period, the Group recognised a non-cash net impairment charge of $117.4
million (2022: $81.0 million charge). This charge primarily reflected
production and cost profile updates on non-operated assets, partially offset
by higher forecast oil prices.
Other income and expenses
The periodic review of the net fair value of the contingent consideration owed
by the Group to bp related to the Magnus acquisition led to $69.7 million of
non-cash income (2022: $232.5 million non-cash expense), driven by adjustments
to the discount rate (2023: 11.3%, 2022: 10.0%) and forward cost assumptions,
partially offset by higher forecast long-term oil prices.
A non-cash charge of $32.8 million has been recognised to reflect a net
increase in the decommissioning provision of fully impaired non-producing
assets (including the Thistle decommissioning linked liability) (2022:
non-cash income of $42.8 million).
Also included within other expenses are costs associated with EnQuest's Veri
Energy business of $1.6 million (2022: $1.2 million).
Adjusted EBITDA
Adjusted EBITDA was $824.7 million, down 15.8% compared to 2022 ($979.1
million).
Finance costs
The Group's overall finance costs of $230.9 million were 8.6% higher than in
2022 ($212.6 million) primarily driven by higher interest charges, reflecting
higher prevailing interest rates, and the unwinding of discounting on
contingent consideration related to the acquisition of Magnus and
decommissioning and other provisions, partially offset by lower fees
associated with the Group's refinancing activities.
Taxation
The 2023 tax charge was impacted by the first full year of the UK EPL at the
higher rate of 35% (2022 reflected seven months of UK EPL at 25%).
The $262.6 million total tax charge includes a $77.2 million net EPL charge,
which is calculated on a higher profit before tax, and the impact of limited
corporation and supplementary corporation tax relief on impairments related to
assets where historical deferred tax initial recognition exemptions have
already been applied (2022: $244.4 million tax charge).
The Group's effective tax rate for the period was a charge of 113.3% (2022:
charge of 120.3%), which primarily reflects the non-deductibility of various
cost items under EPL.
EnQuest has recognised UK North Sea corporate tax losses of $2,007.9 million
at 31 December 2023 - the reduction in the period reflecting utilisation of
ring-fence corporation tax losses against the Group's profits before tax.
Cash flow, net debt and liquidity
Reflecting strong free cash flow generation in 2023 of $300.0 million (2022:
$518.9 million), EnQuest net debt at 31 December 2023 amounted to $480.9
million, a $236.2 million year-on-year reduction (31 December 2022: $717.1
million). The Group ended the year with $313.6 million of cash and cash
equivalents (2022: $301.6 million), and cash and available facilities
totalling $498.8 million (2022: $348.9 million), with the Group's refinancing
activities extending the Group's debt maturities to 2027.
With the Bressay-related farm down proceeds offset by a vendor financing
facility of $141.4 million (from EnQuest to RockRose, arranged to manage the
companies' respective working capital positions) the Bressay transactions were
net debt neutral at 31 December 2023. In the first quarter of 2024, EnQuest
received a $108.8 million repayment of the vendor financing facility. The
remaining amount ($36.3 million) is repayable through net cash flows from the
Bressay field, in accordance with the agreed payment schedule. Both EnQuest
and RockRose are committed to delivering the Bressay development. In the
event, however, that the project does not achieve regulatory approval, there
remains an option to deploy the assets on alternative projects. As such, the
gain from the transaction is reported within deferred income on the balance
sheet.
In the first quarter of 2024, EnQuest repaid the outstanding $140.0 million
principal on its RBL facility. The facility remains available to EnQuest for
future drawdown.
- Ends -
For further information, please contact:
EnQuest PLC Tel: +44 (0)20 7925 4900
Amjad Bseisu (Chief Executive)
Jonathan Copus (Chief Financial Officer)
Craig Baxter (Head of Investor Relations)
Teneo 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://url.uk.m.mimecastprotect.com/s/WeUyCJ859cpzxAkhGHeSi?domain=google.com)
.
EnQuest investor relations team will be hosting a presentation via Investor
Meet Company, primarily focused on the Company's retail investors on 11 April
at 14:00 - London time.
The presentation is open to all existing and potential shareholders. Questions
can be submitted pre-event via your Investor Meet Company dashboard up until
9am the day before the meeting or at any time during the live presentation.
Investors can sign up to Investor Meet Company for free and add to meet
ENQUEST PLC via:
https://www.investormeetcompany.com/enquest-plc/register-investor
(https://protect-eu.mimecast.com/s/tLY9CEq4VUlXxV8fNKiaE?domain=investormeetcompany.com)
Investors who already follow ENQUEST PLC on the Investor Meet Company platform
will automatically be invited.
Notes to editors
This announcement has been determined to contain inside information. The
person responsible for the release of this announcement is Chris Sawyer,
General Counsel and Company Secretary.
ENQUEST
EnQuest is providing creative solutions through the energy transition. As an
independent energy company with operations in the UK North Sea and Malaysia,
the Group's strategic vision is to be the partner of choice for the
responsible management of existing energy assets, applying its core
capabilities to create value through the transition.
EnQuest PLC trades on the London Stock Exchange.
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
All figures quoted are in US Dollars and relate to Business performance unless
otherwise stated.
Overview
Since we set our strategic priorities of 'deliver, de-lever and grow' at the
end of 2018, we have made significant progress; consistently delivering
against production, operational and cost targets, which in turn has enabled us
to generate material free cash flows, even during periods of reduced commodity
prices. Against the backdrop of a challenging fiscal environment in the UK, we
have reduced EnQuest net debt by more than $1.5 billion since its peak and
have aligned outstanding debt maturities in 2027. Now is the time for EnQuest
to build on that strong foundation as we pivot to growth during 2024 and
initiate our first ever return of capital to shareholders.
During 2023, the Group once again delivered a strong operational and financial
performance. Production uptimes were high across the portfolio while
maintaining discipline in our cost management and investment decisions drove
expenditure lower than 2023 guidance, generating free cash flow of $300.0
million and enabling the reduction of EnQuest net debt to $480.9 million.
From a growth perspective, we have positioned ourselves well to transact by
ending 2023 with $498.8 million of liquidity, representing a combination of
cash and headroom within our borrowing facilities. The Group has an
established track record of executing value-accretive, quick payback
acquisitions and, having extended the economic lives of all nine of the assets
we have operated by a minimum of ten years, we will look to utilise our
differentiated capabilities and advantaged tax position to grow the business
through M&A.
We also realised value within the existing portfolio by selling a 15.0% share
of both the Bressay licence and the EnQuest Producer FPSO; a transaction which
represents an important step in moving the Bressay project forward.
Since 2018, we have materially reduced our absolute Scope 1 and 2 emissions
and in 2023, we launched Veri Energy ('Veri'), a wholly owned subsidiary of
EnQuest, as the logical next step in the strategic evolution of EnQuest's new
energy and decarbonisation ambitions, which are initially focused on the
strategically advantaged Sullom Voe Terminal site.
Throughout the year, we reinforced our position as a leading exponent of
decommissioning activities, delivering another record year as the most
productive well plug and abandonment ('P&A') campaign in the northern
North Sea, demonstrating our differentiated capability through an average well
plug and abandonment cost which leads our peer group.
Our enhanced business model spans the energy transition, ensuring that through
time the transition is managed in a just and sustainable manner. By
responsibly managing existing assets, we will continue to contribute to energy
security today while advancing our new energy and decarbonisation
opportunities through Veri Energy to support a future lower-carbon energy
system, before safely decommissioning those assets. Our business model is
underpinned by several complementary, transferable, proven capabilities and
provides long-term opportunities for our people.
Market conditions
Commodity prices
During 2023, global markets predominantly operated within a price range of
$70/bbl to $90/bbl, except for a short period of escalated prices during
September. This range reflected softer pricing than that seen during 2022,
with a number of economic and geopolitical impacts offsetting each other. 2023
saw an increase in demand for hydrocarbons as global economies continued the
path of industrial recovery post-pandemic but the impact on commodity prices
was offset by an increase in US shale production of around 1.5 million barrels
of oil per day, as well as the emergence of additional incremental non-OPEC
supply, predominantly from Brazil, Guyana and Canada. These supply impacts led
OPEC to institute production cuts, which drove the September 2023 price spike
but which ultimately resulted in a stabilisation of prices towards the end of
the year. The geopolitical environment has also caused uncertainty within
global markets amid a continuation of the Russia-Ukraine conflict in Europe
and escalating tensions in the Middle East as war broke out between Israel and
Hamas in October. Supply concerns have escalated and dissipated at various
junctures during the fourth quarter of 2023 and continued into 2024 with US-UK
missile strikes to protect the safe passage of maritime trade in the Red Sea.
Fiscal uncertainty
Following the introduction, and subsequent amendment, of the Energy Profits
Levy ('EPL') during 2022, 2023 represented the first full year of the windfall
tax on oil and gas producers, at an increased headline rate of 35%, impacting
the Group's profitability. As expected, the EPL has impacted access to capital
across the sector, with the most significant on EnQuest being the reduced
borrowing base within the Group's RBL facility. Our robust financial
performance has enabled EnQuest to accelerate repayments against the RBL, with
the 2023 year end drawn balance of $140.0 million being further fully repaid
in the first quarter of 2024, while the October 2023 7.00% Sterling retail
bond was settled and funds fully drawn under a new $150.0 million term loan
facility. Going forward, with a strong balance sheet, we have a fairway of
opportunity to grow the business, ahead of debt maturities which are aligned
in 2027.
Clearly, a volatile fiscal regime imposes significant challenges on any
business and the extension of EPL to 2029 announced in the Spring Budget
represented the fourth amendment to UK sector taxation in the last two years.
However, EnQuest has a track record of demonstrating resilience, creativity
and adaptability and can generate opportunities in such circumstances. The EPL
has resulted in a number of industry participants accelerating their shift in
focus away from the UK North Sea. Our significant tax loss position and the
impact of the EPL on marginal tax rates means that the transfer of assets to
EnQuest ownership would increase their relative value to a multiple of that in
the hands of existing owners. As such, I am confident we will grow the
business through M&A, initially in the UK and then internationally.
Operational performance
EnQuest's average production was in line with the mid-point of guidance at
43,812 Boepd, under-pinned by strong production uptime across the portfolio,
including at Kraken where an efficient return to service of the FPSO following
the anomalous failure of transformer units limited the impact on production. I
was very proud of the EnQuest team which, working alongside the vessel owner,
Bumi Armada, reinstated production on a single train basis within 30 days and
then full production capacity in around two months.
The well programme at Magnus included the successful completion of the North
West Magnus injector well, which came online in May to support the 2022
producer well, alongside two further infill wells which produced first oil in
August and December, respectively. Demonstrating EnQuest's differentiated
operating capability, Magnus production efficiency in 2023 was 88%,
representing a 22% improvement versus 2022.
In Malaysia, average production for the year was 7,437 Boepd, representing a
15% increase over 2022 volumes. This increase includes c.600 Boepd associated
with Seligi 1a gas, to which Petronas hold the entitlement, and which is
produced and handled by EnQuest in exchange for a gas handling and delivery
fee, as well as strong operational performance and production uptime of 90%.
During 2023, we produced c.16 MMboe of our year-end 2022 2P reserves base.
This reduction in 2P reserves was partially offset by transfers from 2C
resources at Magnus, net of other technical revisions. As such, 2P reserves at
the end of the year were around 175 MMboe, down from c.190 MMboe reported at
the end of 2022. We continue to have material 2C resources of around 389
MMboe, with Bressay and Bentley each holding more than 100 MMboe of net 2C
resources, while Magnus and Kraken in the UK and PM8/Seligi offshore Malaysia
also hold material 2C resources.
The launch of Veri in December 2023 recognises our position at SVT provides a
strategically advantaged, sustainable and tangible basis upon which to expand
the Group's role in the energy transition; a position which is predicated on a
capital-light approach to investment and which was further enhanced by the
award of four carbon storage licences in the North Sea Transition Authority's
('NSTA') first UK licensing round.
Our UK decommissioning team continued to demonstrate excellence in the
execution of well P&A activities at an average cost of c.£2.5 million per
well, significantly below the NSTA benchmark of c.£4.3 million. This
programme saw the successful execution of 25 well P&As across the Heather
and Thistle fields, exceeding the record for the most prolific multi-asset
P&A campaign in the northern North Sea, previously set by EnQuest in 2022.
Financial performance
The Group's adjusted EBITDA and statutory gross profit decreased by 15.8% to
$824.7 million and 17.2% to $540.7 million, respectively, reflecting lower
realised oil prices and production. Operating costs for the year of $347.2
million were 12.4% lower than 2022, primarily due lower diesel costs and
higher lease charter credits associated with the unplanned downtime at Kraken.
Unit operating costs decreased 3.5% to $21.9/Boe, reflecting the impacts on
costs noted above. Cash generated by operations decreased to $854.7 million,
down by 16.7% compared to 2022, although free cash flow generation remained
robust, delivering $300.0 million.
The Group's continued solid financial and operating performance during the
year drove further strengthening of the balance sheet and enabled the focus of
the business to pivot to growth in 2024. We are also delighted to announce our
first shareholder return programme and intend to deploy $15.0 million of
capital in a share buyback programme during 2024.
Environmental, Social and Governance
The health, safety and wellbeing of our employees remains our top priority. In
2023, we delivered another upper quartile Lost Time Incident ('LTI')
frequency1 rate but were disappointed to see three LTIs during the year. We
remain laser focused on SAFE results with no harm to our staff and contractors
and have engaged in a programme of intervention, assessing root causes of
incidents and working closely with the contractors involved to ensure that
everyone is aligned with our safety culture, trained on equipment and
procedures and empowered to stop a task should a safer method be identified.
As outlined earlier, we have made excellent progress in reducing absolute
Scope 1 and 2 emissions in recent years, with the Group's CO2 equivalent
emissions reduced by 23% since 2020 and the UK's emissions down by c.41% since
2018. This progress is significantly ahead of the Group's targeted reductions
and those set by the UK Government's North Sea Transition Deal, providing a
strong foundation for our commitment to reach net zero by 2040. Looking ahead,
the Group has approved investments designed to reduce future carbon emissions
and operating costs across the portfolio, including the new stabilisation
facility and power generation projects at SVT and the potential gas tie-back
solution from Bressay to Kraken. At the same time, we continue to optimise
sales of Kraken cargoes directly to the shipping fuel market, avoiding
emissions related to refining and helping reduce sulphur emissions.
This year saw a number of changes to our Board, with Non-Executive Directors
Howard Paver, Carl Hughes and John Winterman stepping down, to be succeeded by
Mike Borrell and Karina Litvack, although Karina unfortunately had to resign
her position due to a conflict. I would like to thank Howard, Carl, John and
Karina for their contributions, and I look forward to working with the
refreshed Board as we execute on our growth strategy.
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)
2024 performance and outlook
Production performance to the end of February was 44,498 Boepd. Our full-year
net production guidance of between 41,000 and 45,000 Boepd includes the
impacts from drilling campaigns at Magnus, PM8/Seligi and Golden Eagle and
required maintenance activities across the portfolio.
Operating costs are expected to be approximately $415.0 million, while capital
expenditure is expected to be around $200.0 million, with decommissioning
expenditure expected to total approximately $70.0 million.
Longer-term development
Our strategy and business model have evolved to align to our aims of
delivering value-driven growth and establishing EnQuest as a key player in a
just energy transition. We have established a track record of executing
acquisitions and optimising asset lives, underpinned by our operating
capabilities and the transactional flexibility which is derived from our
improved liquidity.
Our position as a top quartile operator, alongside our advantaged tax position
in the UK, enhances our M&A credentials as a responsible owner and
operator of existing assets and infrastructure as we transition to a
lower-carbon energy system, offering our people long-term opportunities. We
also believe that our core capabilities and top quartile operating performance
can be replicated across other geographies as we seek to grow and diversify
internationally.
2023 was a year of continued strong performance for the Group which was
achieved with the support of all our stakeholders; our people, shareholders,
investors, lenders, partners and suppliers. I thank all for their
contributions throughout 2023 and I am excited about delivering EnQuest's next
growth phase during this pivotal year.
Operational review
Upstream operations
2023 Group performance summary
Production of 43,812 Boepd reflected improved performances at Magnus and at
PM8/Seligi, strong production uptimes across the operated portfolio and the
Group's investment in low-cost, quick-payback drilling and wellwork campaigns,
partially offsetting the impact of natural field declines.
Magnus
2023 performance summary
2023 production of 15,933 Boepd was 26% higher than the 2022 figure of 12,641
Boepd, driven by significantly improved production efficiency of 88% (2022:
66%) following improvements to rotating equipment performance, including gas
compressors and power generation units. The Group executed an extensive
wellwork programme, with three wells returned to service following P seal
repair/replacement works, execution of a perforation scope and the completion
of an infill drilling programme which included the North West Magnus injector
in May and two further infill wells which came online in August and December,
respectively. In addition, slot recovery activity continued to enable the
delivery of future infill drilling opportunities, with the completion of the
B6 well plug and abandonment ('P&A') during July 2023.
The planned annual maintenance shutdown was completed in 20 days, versus the
original planned duration of 24 days, with all major scopes executed. The
shutdown involved 10,000 manhours of work being completed with zero lost time
incidents.
2024 outlook
The five-yearly rig recertification of the Magnus platform rig commenced in
early January and is expected to run until the second quarter of 2024, with
infill drilling activity to recommence thereafter. A shutdown of around three
weeks is planned in the third quarter to complete scheduled safety-critical
activities, while further asset integrity maintenance and plant improvement
opportunities will continue to be assessed and implemented throughout the year
in order to minimise platform vulnerability. It is anticipated that two wells
will be drilled in the second half of 2024, with the expectation that Magnus
production will be higher than 2023. With 2C resources of c.28 MMboe, Magnus
offers the Group significant low-cost, quick payback drilling opportunities in
the medium term.
Kraken
2023 performance summary
Average net production in 2023 was 13,580 Boepd (2022: 18,394 Boepd), which is
reflective of high uptime before and after the anomalous failure of HSP
transformer units during May. Working alongside the vessel owner, Bumi Armada,
the EnQuest asset team exemplified differentiated operational capability by
limiting the impact of this outage, resuming production on a phased basis
within 30 days of the outage and then, through the refurbishment/rebuild and
reinstatement of transformer units, returned Kraken to full production in
early-August. Subsequently, the Group oversaw a return to top quartile
performance, with the Floating, Production, Storage and Offloading ('FPSO')
delivering production efficiency and water injection efficiency of 98% and
99%, respectively, for the final four months of the year. For the full year
2023, production efficiency was 86% (2022: 93%) and water injection efficiency
was 85% (2022: 93%).
Production in the second half of the year benefited from the removal of two
planned periods of single train operations, with the Group having executed
maintenance work while production at the FPSO was shut-in. In addition,
delivery and deployment of new HSP transformer units has provided increased
resilience to production capacity, with further HSP and water injector
transformer replacements planned during 2024.
The Group continues to optimise Kraken cargo sales into the shipping fuel
market, with Kraken oil a key component of International Maritime Organization
('IMO') 2020 compliant low-sulphur fuel oil while avoiding refining-related
emissions.
2024 outlook
No shutdown is planned during 2024 but it is expected that a ten-day period of
single processing train operations will be undertaken in order to execute
safety-critical maintenance work.
The Group has procured a mobile offshore drilling unit ahead of a planned
return to drilling at Kraken during 2025. EnQuest will purchase selected long
lead equipment during 2024 required to facilitate the two-well sidetrack
programme. With c.33 MMboe of 2C resources, there remains significant
opportunity in terms of main field side-track drilling opportunities, along
with further drilling within the Pembroke and Maureen sands, while Kraken
production will be subject to natural decline in 2024.
Golden Eagle
2023 performance summary
2023 net production was below the Group's expectations at 4,199 Boepd (2022:
6,323 Boepd), with asset production efficiency in excess of 90% (2022: 95%).
Following the arrival of the drilling rig in August 2023, drilling of the
first well in the 2023/24 platform drilling programme commenced in October
2023 and the well was brought online in January 2024. This is the first well
of an anticipated four-well programme, which is due to be completed in
mid-2024.
2024 outlook
The operator has scheduled a shutdown of around one week in the summer of
2024, with subsequent major shutdowns expected to be required every two to
three years.
Other North Sea assets
2023 performance summary
Production in 2023 averaged 2,663 Boepd (2022: 3,442 Boepd), largely in line
with expectations and reflecting strong uptime of 83% (2022: 87%) at the
Greater Kittiwake Area.
At Alba, performance continued largely in line with the Group's expectations.
Work continued towards the development of the wider Kraken area, including a
Bressay gas tie-back solution and an early production solution project at
Bressay with RockRose Energy now a joint venture partner on the Bressay
project, with regulatory approval granted in March 2024.
2024 outlook
At GKA, a one-week shutdown is planned during the second quarter, as well as a
short shutdown of related infrastructure.
At Bressay, EnQuest continues to actively explore further farm-down
opportunities and development planning of the asset, with the aim to utilise
its expertise in heavy oil developments to access the c.115 MMboe of 2C
resources. In 2024, the Group aims to progress the tie-back of the Bressay
field's gas cap to Kraken, displacing diesel that currently powers Kraken
operations.
PM8/Seligi
2023 performance summary
Average production of 7,437 Boepd was 15% higher than 2022. This increase
includes 604 Boepd associated with Seligi 1a gas, to which Petronas holds the
entitlement, and which is produced and handled by EnQuest in exchange for a
gas handling and delivery fee, as well as strong operational performance and
production uptime of 90% (2022: 86%).
Following the drilling of the commitment well at Block PM409, the well was
plugged and abandoned dry. Following confirmation from Petronas that all well
requirements had been met by EnQuest, no further drilling is planned for
PM409.
2024 outlook
A two-week shutdown at PM8/Seligi to undertake asset integrity and maintenance
activities is planned for the summer, which will help to improve reliability
and efficiency at the field. To further improve compressor reliability,
turbine control panel upgrade is planned for the second train at the end of
the third quarter.
The Group plans to drill three infill wells and deliver three well workovers,
with six wells to be plugged and abandoned. These well programmes will
mobilise at the end of the first quarter of the year.
EnQuest has significant 2P reserves and 2C resources of c.28 MMboe and c.80
MMboe, respectively, with future multi-well annual drilling programmes
planned. The Group continues to work with the regulator to assess the
opportunity to develop the additional gas resource at PM8/Seligi to meet
forecast Malaysian demand.
Decommissioning
Performance summary
Within EnQuest's decommissioning team, 2023 represented another year of
record-breaking delivery, enhancing the Group's strong track record of
executing multi-asset abandonment campaigns. As the Thistle and Heather
project teams look ahead to the culmination of the respective well plug and
abandonment ('P&A') campaigns, preparation is underway for the 2025
removals programmes at these two major platforms in the North Sea.
Well decommissioning
At both the Heather and Thistle fields, the extensive programme of well
P&A continued apace throughout the year. Thistle successfully abandoned 13
wells whilst Heather completed 12 wells by year end, while a further well at
each asset was partially completed as at 31 December 2023. In addition to the
completion of 25 well abandonments across the two platform rigs, the Thistle
project team implemented a third activity string, in the form of a hydraulic
workover unit, to accelerate the recovery of conductors on available wells.
This resulted in seven wells being abandoned to the final stage of the well
P&A process, which focuses on removing the surface infrastructure and
ensuring the well poses no future environmental or safety risks, reducing the
critical path of the main rig activity and resulting running costs of the
asset.
Both the Thistle and Heather project teams are targeting completion of their
well P&A campaigns by the end of the first quarter of 2025 and remain on
target to permanently disembark the respective platforms later that year.
Throughout 2023, EnQuest has also progressed the detailed engineering work on
the subsea wells at Alma Galia, Dons and Broom, while continuing to discuss
the future work programmes with the North Sea Transition Authority.
Preparation for removal
Beyond well P&A activity, the Heather project team plans to execute
multiple work scopes in 2024, including the flushing of pipelines, preparing
the Broom riser for decommissioning and other engineering and cleaning
scopes.
In the second half of the year, the contract award for the disposal of the
Heather topsides was awarded, while the removal of the platform topsides will
be completed in a single lift in 2025 utilising the Pioneering Spirit heavy
lift vessel ('HLV').
At Thistle, the project team demonstrated its capability by delivering
multiple key scopes. Subsea campaigns covering essential IRM activities,
preparatory work for conductor removal and the flushing and final
disconnection of pipeline PL166 were all completed successfully. The team also
engaged a conductor pulling unit, which enabled simultaneous P&A
operations alongside the main rig.
Following an extensive commercial exercise, EnQuest awarded the contract for
the Thistle topsides and jacket Engineering, Preparation, Removal and Disposal
('EPRD') works to Saipem. The removal operations are due to take place from
2026 onwards and will see all 32 modules of the Thistle platform lifted onto
the semi-submersible heavy lift vessel S7000 and returned to shore in four
separate voyages.
Throughout 2024, the project teams across Heather and Thistle will be focused
on the engineering required to prepare for the heavy lift operations as well
as exploring opportunities to further optimise schedule, cost and delivery
targets where possible.
Given increased competition in the heavy lift vessel market, with the
evolution of several largescale renewable projects being sanctioned by the
governments of European countries, EnQuest will manage the execution of the
heavy lift scopes within multi-year windows so as to retain flexibility and
mitigate availability concern.
Infrastructure - Midstream
Within its Midstream directorate, EnQuest operates the Sullom Voe Terminal
('SVT') on Shetland and around 1,000km of pipelines.
Safe, stable operations
Throughout 2023, the Group continued to deliver safe, stable and effective
operations for both East of Shetland and West of Shetland oil and gas,
delivering 100% uptime for both oil streams, and 99% uptime for West of
Shetland gas. In addition, the Sullom Voe Terminal ('SVT') power station
achieved 100% power delivery throughout the period. The terminal, which
celebrated its 45th anniversary of oil production in November 2023, also
achieved four million man hours Lost Time Incident ('LTI') free during the
third quarter of 2023.
Decarbonisation
The Group is focused on right-sizing SVT for future operations. During 2023,
EnQuest successfully matured and gained support for two strategic projects to
connect the terminal to the UK's electricity grid and the construction of new
stabilisation facilities ('NSF'). Completion of the NSF is expected to enable
the Group to meet the North Sea Transition Authority ('NSTA') target of zero
routine flaring obligations by 2030 while, taken together, delivery of these
two projects is expected to result in a 90% reduction in overall emissions
from SVT and the Engie-operated Sullom Voe power station. The anticipated
reduction in future emissions set out within these projects led to EnQuest's
SVT operation being shortlisted for a 2023 Offshore Energies UK
Decarbonisation Award.
EnQuest has awarded a strategic contract for the phased partial
decommissioning of the existing oil stabilisation and processing facilities.
This will create space onsite for future new energy projects such as carbon
storage, the production of green hydrogen and offshore electrification.
People and community
The Group has an established apprentice programme at SVT, with three
apprentices successfully graduating in 2023. Further, EnQuest renewed a
four-year programme which enables apprentices to be sponsored at the terminal,
with the adoption of one apprentice into the programme due to his site-based
experience. Separately, the Group launched a new graduate programme in 2023,
with two graduates recruited into SVT, one of whom is a resident of Shetland.
Also in 2023, the programme's most recent graduate attained Chartered Engineer
status with the Institution of Chemical Engineers.
Key projects
Carbon capture and storage ('CCS')
Veri Energy is seeking to develop a flexible carbon storage solution that can
transport and permanently store up to 10mtpa of CO2 from isolated emitters in
the UK and Europe. CO(2) captured by emitters will be transported via ship to
SVT from where it will be transported via repurposed pipeline infrastructure
for permanent geological storage in depleted oil and gas reservoirs.
In August 2023, EnQuest successfully secured carbon storage licences as part
of the first round of UK carbon sequestration licences issued by the North Sea
Transition Authority ('NSTA'). The licences areas CS013, CS014, CS015 and
CS016 are some 99 miles northeast of Shetland and include fields currently
operated by EnQuest, the Magnus and Thistle fields, as well as the
non-operated Tern, Otter and Eider fields. These sites are large,
well-characterised deep storage formations connected by significant existing
infrastructure to the Sullom Voe Terminal on Shetland.
Green hydrogen
Veri Energy is progressing evaluation of a 50 megawatt green hydrogen project
at Sullom Voe. In February 2024, Veri received an award of £1.74 million in
grant funding from the UK government's Net Zero Hydrogen Fund ('NZHF') to
support a front-end engineering and design study for the project.
Renewable power
Veri Energy is also exploring the potential to develop renewable power to
provide electrification for existing and prospective oil and gas facilities.
Financial review
Introduction
Strong free cash flow generation in the period of $300.0 million (2022: $518.9
million) drove a reduction in EnQuest net debt of 32.9%, to $480.9 million (31
Dec 2022: $717.1 million). At 31 December 2023, the Group's leverage ratio was
0.6x, close to its target of 0.5x, while cash and available facilities had
increased to $498.8 million (2022: $348.9 million) with all debt now maturing
in 2027.
During December, EnQuest announced the sale of a 15.0% equity share in the
Bressay licence and the EnQuest Producer FPSO for a total consideration of
£46.0 million (c.$57.0 million). Subsequently, the Group received $85.6
million for a 15.0% farm-down of capital items identified as suitable for use
on the Bressay development. Through these transactions the Group has realised
near-term value, expecting to yield c.$58.0 million post-tax cash flow in
2024, and delivered an important step in moving the project forward.
The Group's improved balance sheet, liquidity position and significantly
advantaged tax position means EnQuest is well placed to pursue growth
opportunities and deliver its first program of shareholder returns, committing
to a $15.0 million buy back that will be completed during 2024.
Income statement
Revenue
Group production averaged 43,812 Boepd, with strong uptimes across the
portfolio and investment in low-cost, quick-payback drilling and wellwork
campaigns partially offsetting the impact of natural field declines (2022:
47,259 Boepd).
Brent prices in the period averaged $82.5/bbl (18.2% below 2022: $100.8/bbl)
and the average day ahead gas price decreased to 98.9p/Therm (51.4% below
2022: 203.5p/Therm). Pre-hedging, the average oil price realised by EnQuest
was $82.2/bbl (19.9% below 2022: $102.6/bbl). Post-hedging, realised oil
prices averaged $81.4/bbl, narrowing the discount year-on-year to 8.4%
($88.9/bbl).
Reflecting these drivers, reported revenue totalled $1,487.4 million, a 19.8 %
decline on 2022 ($1,853.6 million). Within this figure, oil sales accounted
for $1,127.4 million, 25.7% below 2022 ($1,517.7 million).
Realised losses on commodity hedges totalled $11.3 million (2022: losses of
$203.7 million). Unrealised gains on these contracts (from mark-to-market
movements) totalled $28.5 million (2022: unrealised gains of $14.5 million).
Revenue from the sale of condensate and gas, totalling $339.0 million (2022:
$514.2 million), primarily relates to the onward sale of third-party gas that
was not required for injection activities at Magnus. The contribution from
these third-party gas volumes is offset in Cost of sales. Tariffs and other
income generated a further $3.8 million (2022: $11.0 million), including
income from the transportation of Seligi associated gas.
Cost of sales
2023 2022
$ million $ million
Production costs 308.3 347.8
Tariff and transportation expenses 41.7 43.3
Realised (gain)/loss on derivatives related to operating costs (2.8) 5.4
Operating expenditures1 347.2 396.5
Charge/(credit) relating to the Group's lifting position and inventory (4.2) (15.6)
Other cost of operations 305.9 487.9
Depletion of oil and gas assets 292.2 327.0
Other cost of sales 5.7 4.9
Cost of sales 946.8 1,200.7
Unit operating cost(2,3) $/Boe $/Boe
- Production costs 19.3 20.2
- Tariff and transportation expenses 2.6 2.5
Average unit operating cost 21.9 22.7
Notes:
1 See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP Measures' starting on page 65
2 Calculated on a working interest basis
3 Excludes realised (gain)/loss on derivatives related to operating
costs
The Group demonstrated effective cost control to mitigate the effects of
underlying inflationary pressures, through extensive supplier engagement and
agreeing fixed rate contracts for certain services, and the strengthening
Sterling to US Dollar exchange rate with the Group's foreign exchange hedging
delivering gains of $5.2 million in the period, noting c.83% of Group
operating costs are denominated in Sterling.
Group operating costs of $347.2 million were 12.4% lower than in 2022 ($396.5
million), with unit operating costs (excluding foreign exchange hedging)
decreasing to $21.9/Boe (2022: $22.7/Boe). The reduction in operating costs
was driven by work programme optimisation across the portfolio, higher lease
charter credits and lower diesel costs at Kraken.
Other costs of operations of $305.9 million were significantly lower than in
2022 ($487.8 million), driven predominantly by lower gas prices impacting the
cost of Magnus-related third-party gas purchases which are sold on of $294.0
million (2022: $452.8 million).
Depletion expense of $292.2 million was 10.6% lower than in 2022 ($327.0
million), mainly reflecting the impact of lower production.
Impairment
In the period, the Group recognised a non-cash net impairment charge of $117.4
million (2022: $81.0 million charge). This charge primarily reflected
production and cost profile updates on non-operated assets, partially offset
by higher forecast long-term oil prices.
Other income and expenses
The Group has recognised net income in the period $39.3 million (2022: net
expense of $152.4 million).
The periodic review of the net fair value of the contingent consideration owed
to bp relating to the Magnus acquisition led to $69.7 million of non-cash
income (2022: $232.5 non-cash expense), driven by adjustments to the discount
rate (2023: 11.3%, 2022: 10.0%) and forward cost assumptions, partially offset
by higher forecast oil prices.
Against a backdrop of inflationary pressures and Sterling strengthening
against the US Dollar, a non-cash charge of $32.8 million has been recognised
to reflect a net increase in the decommissioning provision of fully impaired
non-producing assets (including the Thistle decommissioning linked liability)
(2022: non-cash income of $42.8 million, driven by an increase in the discount
rate applied and Sterling weakening against the US Dollar).
Also included within other expenses are costs associated with EnQuest's Veri
Energy business of $1.6 million (2022: $1.2 million).
Adjusted EBITDA(1)
2023 2022
$ million $ million
Profit from operations before tax and finance income/(costs) 456.2 411.9
Unrealised hedge gain (28.5) (14.5)
Depletion and depreciation 298.3 333.2
Impairment 117.4 81.0
Net other (income)/expense (33.7) 183.1
UKA forward purchase losses 3.8 4.9
Change in well inventories (0.6) 0.8
Net foreign exchange loss/(gain) 11.8 (21.3)
Adjusted EBITDA1 824.7 979.1
Note:
1 See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP Measures' starting on page 65
Adjusted EBITDA was $824.7 million, down 15.8% compared to 2022 ($979.1
million).
Finance costs
The Group's overall finance costs of $230.9 million were 8.6% higher than in
2022 ($212.6 million).
The net effect from the reduction in the Group's outstanding loans and
borrowings and higher prevailing interest rates, resulted in a higher overall
interest charge for 2023 of $89.7 million (2022: $77.2 million) - although
this was partially offset by lower fees associated with the Group's
refinancing activities (2023: $7.9 million; 2022: $35.3 million).
Finance charges were also higher due to the unwinding of discounting on
contingent consideration related to the acquisition of Magnus (2023: $58.9
million; 2022: $36.4 million) and decommissioning and other provisions (2023:
$25.4 million; 2022: $17.8 million).
Other charges included in finance costs are lease liability interest of $43.8
million (2022: $39.2 million) and other financial expenses of $5.3 million
(2022: $6.8 million), primarily being the cost for surety bonds to provide
security for decommissioning liabilities.
Profit/loss before tax
Reflecting the movements above, the Group's profit before tax of $231.8
million was $28.6 million higher than 2022 ($203.2 million).
Taxation
The 2023 tax charge was impacted by the first full year of the UK EPL at the
higher rate of 35% (2022 reflected seven months of UK EPL at 25%).
The $262.6 million total tax charge includes a $77.2 million EPL charge, which
is calculated on a higher profit before tax, and the impact of limited
corporation and supplementary corporation tax relief on impairments related to
assets where historical initial recognition exemptions for deferred tax have
already been applied (2022: $244.4 million tax charge, which included the
initial recognition of a $178.3 million non-cash deferred tax liability
associated with the EPL partially offset by a credit for the non-cash
recognition of undiscounted deferred tax assets of $127.0 million).
The Group's effective tax rate for the period was a charge of 113.3% (2022:
charge of 120.3%).
EnQuest has recognised UK North Sea corporate tax losses of $2,007.9 million
at 31 December 2023 - the reduction in the period reflecting utilisation of
ring-fence corporation tax losses against the Group's profits before tax.
Unrecognised tax losses are disclosed in note 7(d) on page 43.
Due to this recognised tax loss position, no significant corporation tax or
supplementary charge is expected to be paid on UK operational activities for
the foreseeable future.
The Group paid its 2022 EPL charge in October 2023 and is expected to make
further EPL payments in October each year for the duration of the levy. The
Group also paid cash corporate income tax on the Malaysian assets, which will
continue throughout the life of the Production Sharing Contract.
Profit/loss for the year
The Group's total loss after tax was $30.8 million (2022: loss of $41.2
million). The high effective tax rate was primarily driven by the current tax
impact of EPL, reflecting its high level of non-deductible expenditures
related to financing and decommissioning costs, and limited corporation and
supplementary corporation tax relief on impairments related to assets where
historical initial recognition exemptions have been applied.
Earnings per share
The Group's reported basic loss per share was 1.6 cents (2022: loss of 2.2
cents) and reported diluted loss per share was 1.6 cents (2022: loss of 2.2
cents).
Cash flow, EnQuest net debt and liquidity
Reflecting strong free cash flow generation in 2023 of $300.0 million (2022:
$518.9 million), EnQuest net debt at 31 December 2023 amounted to $480.9
million, a $236.2 million year-on-year reduction (31 December 2022: $717.1
million). The movement in EnQuest net debt was as follows:
$ million
EnQuest net debt 1 January 2023 (717.1)
Net cash flows from operating activities 754.2
Cash capital expenditure (152.2)
Magnus profit share payments (65.5)
Golden Eagle contingent consideration payment (50.0)
Finance lease payments (135.7)
Proceeds from farm-down 141.4
Vendor financing facility (141.4)
Net interest and finance costs paid (100.0)
Other movements, including net foreign exchange on cash and debt (14.6)
EnQuest net debt 31 December 20231 (480.9)
Note:
1 See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP Measures' starting on page 65
The Group's reported net cash flows from operating activities were $754.2
million, down 19.0% compared to 2022 ($931.6 million). The overall reduction
was primarily driven by lower revenue, partially offset by lower cash opex.
In line with guidance, the Group's reported net cash flows used in investing
activities increased $101.5 million to $262.7 million (2022: $161.2 million).
This increase principally reflects: higher capital expenditures of $152.2
million (2022: $115.8 million), which primarily related to Magnus, Golden
Eagle and Malaysia well campaigns and Sullom Voe Terminal projects; the final
Golden Eagle Contingent consideration payment ($50.0 million) and an
additional $19.5 million of Magnus profit share payments (2023: $65.5 million;
2022: $46.0 million).
Cash outflow on capital expenditure is set out in the table below:
Year ended Year ended
31 December 2023
31 December 2022
$ million $ million
North Sea 124.2 85.5
Malaysia 21.0 26.5
Exploration and evaluation 7.0 3.8
152.2 115.8
With the Bressay-related farm down proceeds offset by a vendor financing
facility of $141.4 million (from EnQuest to RockRose, arranged to manage the
companies' respective working capital positions), the Bressay transactions
were net debt neutral at 31 December 2023. In the first quarter of 2024,
EnQuest received $108.8 million repayment of the vendor financing facility.
The remaining amount ($36.3 million) is repayable through net cash flows from
the Bressay field in accordance with the agreed payment schedule. In the
event, however, that the project does not achieve regulatory approval, there
remains an option to deploy the assets on alternative projects. As such,
proceeds from the transaction are reported within deferred income on the
balance sheet.
The Group utilised $478.6 million of cash in financing activities (2022:
$731.2 million) - including further net repayments of the Group's loans and
borrowings totalling $237.1 million (2022: $479.8 million). In this figure,
$260.0 million of the Group's RBL facility was repaid, the October 2023 7.00%
Sterling retail bond was settled (£111.3 million) and funds were fully drawn
under a new $150.0 million term loan facility.
Associated with these borrowings, interest costs totalled $105.9 million
(2022: $103.4 million). In the year, $135.7 million was also paid on finance
leases (2022: $148.0 million).
EnQuest net debt(1)
31 December 2023 31 December 2022
$ million $ million
Bonds 474.7 600.7
RBL 140.0 400.0
Term Loan 150.0 0.0
SVT working capital facility 29.8 12.3
Vendor loan facility - 5.7
Cash and cash equivalents (313.6) (301.6)
EnQuest net debt 480.9 717.1
Note:
1 See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP Measures' starting on page 65
The Group ended the year with $313.6 million of cash and cash equivalents
(2022: $301.6 million), and cash and available facilities totalling $498.8
million (2022: $348.9 million), with the Group's refinancing activities
extending the Group's debt maturities to 2027.
In the first quarter of 2024, EnQuest repaid the outstanding $140.0 million
principal on its RBL facility. The facility remains available to EnQuest for
future drawdown.
Balance sheet
The Group's strong cash generation, improved liquidity position, including
extended maturities of its available debt facilities, and UK tax advantage,
means EnQuest is well positioned to continue delivering its foundation
programmes of capital investment - whilst also pursuing transformational North
Sea and International production acquisitions, and delivering its first
program of shareholder returns.
Assets
Total assets at 31 December 2023 reduced by 6.4% to $3,765.8 million (2022:
$4,024.3 million). This movement is primarily driven by: a reduction of $165.7
million in the Group's deferred tax asset (largely reflecting the impact of
utilising ring-fence corporation tax losses in the period (see note 7)); lower
net PP&E of $180.2 million, including a non-cash net impairment charge of
$117.4 million (see note 10); and a partial offset from recognition of the
Bressay vendor financing facility receivable of $145.1 million (see note 19).
Liabilities
Total liabilities reduced by 6.5% to $3,309.0 million (2022: $3,540.0 million)
- the Group continuing to make material repayments of its debt, resulting in a
materially lower carrying value of $775.2 million (2022: $1,000.3 million)
(see note 18).
Contingent consideration payments related to the acquisitions of Magnus and
Golden Eagle totalled $115.5 million (2022: $46.0 million for Magnus, nil for
Golden Eagle), and a net change in the fair value estimate for Magnus resulted
in a lower outstanding contingent consideration estimate of $507.8 million
(2022: $636.9 million) (see note 22).
Offsetting these reductions are a $57.7 million net increase in the Group's
current and deferred tax liabilities - UK EPL driving a higher income tax
payable provision of $185.5 million (2022: $39.2 million payable) offset by a
$88.7 million lower deferred tax liability of $77.6 million (2022: $166.3
million).
Financial risk management
The Group's activities expose it to various financial risks particularly
associated with fluctuations in oil price, foreign currency risk, liquidity
risk and credit risk. The disclosures in relation to financial risk management
objectives and policies, including the policy for hedging, and the disclosures
in relation to exposure to oil price, foreign currency and credit and
liquidity risk, are included in note 28 of the financial statements.
Going concern disclosure
In recent years, given the prevailing macroeconomic and fiscal environment,
the Group has prioritised deleverage - reducing gross debt (excluding leases)
by c. $1.4 billion since 2017 to $794.5 million at 31 December 2023. During
2023, EnQuest net debt was reduced by $236.2 million (to $481.1 million) and
the Group strengthened its net debt to adjusted EBITDA ratio to 0.6x, close to
EnQuest's target of 0.5x. In this 12-month period, cash and available
facilities increased by $149.9 million, to $498.8 million at 31 December 2023,
and medium-term liquidity is secured, with all the Group's debt maturities now
in 2027.
Against this robust backdrop, EnQuest continues to closely monitor and manage
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 Group's latest approved business plan underpins management's base case
('Base Case') and is in line with the Group's production guidance using oil
price assumptions of $80.0/bbl for 2024 and $75.0/bbl for 2025.
A reverse stress test has been performed on the Base Case indicating that an
average oil price of c.$63.0/bbl over the going concern period maintains
covenant compliance, reflecting the Group's strong liquidity position.
The Base Case has also been subjected to further testing through a scenario
reflecting the impact of the following plausible downside risks (the 'Downside
Case'):
· 10% discount to Base Case prices resulting in Downside Case prices of
$72.0/bbl for 2024 and $67.5/bbl for 2025;
· Production risking of 5.0%; and
· 2.5% increase in operating, capital and decommissioning expenditure
The Base Case and Downside indicates 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.
After making appropriate enquiries and assessing the progress against the
forecast and projections, 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 2027. The viability assumptions are consistent with the going
concern assessment, with the additional inclusion of an oil price of $75.0/bbl
for 2026 and 2027 in the Base Case and consistent plausible downside risks
applied in a Downside Case. This assessment has taken into account the Group's
financial position as at 27 March 2024, 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 27.
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. Under the Group's Base Case projections, 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 2027.
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. 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, from 1 April 2024 the
Directors have hedged a total of 5.0 MMbbls for the remainder of 2024, with
4.1MMbbls through the use of put options with an average floor price of
c.$60/bbl and 0.9MMbbls through swaps at an average price of $86/bbl, and 1.6
MMbbls in 2025 using puts, with an average floor price of c.$60.0/ 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.
Fiscal risk and government take
Unanticipated changes in the regulatory or fiscal environment can affect the
Group's ability to access funding and liquidity. The change to the UK EPL
introduced in the Autumn Statement 2022 materially impacted the RBL borrowing
base and associated amortisation schedule. In the 2023 Autumn Statement on 22
November, the UK Government confirmed that they will bring in legislation for
the Energy Security Investment Mechanism and have agreed to index link the
trigger floor price to CPI from April 2024. The Government also announced that
once the decarbonisation allowance of 80% against EPL is withdrawn (currently
in March 2028), that they will replace this with a new allowance at the same
effective rate against the industry tax regime. In March 2024, the UK
Government announced that the sunset clause for EPL would be extended by a
year to 31 March 2029, although no date has yet been set for when this will be
legislated. Further fiscal changes could be enacted should there be a change
in UK Government at the next general election. The Group will continue to
monitor developments and any potential related impacts.
Access to funding
Prolonged low oil prices, cost increases, production delays or outages and
changes to the fiscal environment could threaten the Group's liquidity and
access to funding.
The Directors recognise the importance of ensuring medium term liquidity. The
maturity dates of July 2027 for the $150.0 million term loan and November 2027
for the $305.0 million high yield bond and the £133.3 million retail bond,
provide a material level of funding throughout the assessed viability period
ending March 2027. The Group has continued to prioritise debt reduction from
free cash flows as evidenced with the RBL being fully repaid in the first
quarter of 2024, materially ahead of schedule.
In assessing viability, the Directors recognise that in a Downside Case
limited additional liquidity would be required, which may necessitate limited
mitigations, such as working capital management, amendments to capital work
programmes, asset farm downs or other financing options. Given the extended
duration of the viability period, the Directors believe such measures can be
executed successfully in the necessary timeframe to maintain liquidity.
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 2027.
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 partner of choice for responsible management of
existing energy assets, applying our core capabilities to create value through
the transition.
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, diversifying its asset base and pursuing new energy and decarbonisation
opportunities;
· 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 Board also
periodically reviews (with senior management) the Group Risk Register, 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 ('CIP') to ensure that key
issues are being adequately identified and actively managed. In addition, the
Group's Audit Committee oversees the effectiveness of the RMF while the
Sustainability Committee 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, the evolution of the
fiscal regime, developments in technology, demographics, the financial,
physical and transition risks associated with climate change and other ESG
trends, 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 made further
progress in the development and execution of its energy transition and
decarbonisation strategy through the Infrastructure and New Energy business,
which was established in 2021 and launched as Veri Energy, a wholly owned
subsidiary of the Group, in 2023. The Group is also conscious that as an
operator of mature producing assets with limited appetite for exploration, it
has limited exposure to investments that 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' (being those assets no longer able to earn an economic
return as a result of changes associated with the transition to a low-carbon
economy).
Within the Group's RMF, the Sustainability Committee has categorised all risk
areas faced by the Group into a 'Risk Library' of 19 overarching risks. For
each risk area, 'Risk Bowties' are used to identify risk causes and impacts,
with these mapped against preventative and containment controls used to manage
the risks to acceptable levels (see diagram below). These Risk Bowties are
periodically reviewed to ensure they remain fit for purpose.
The Board, supported by the Audit Committee and the Sustainability Committee,
has reviewed the Group's system of risk management and internal control for
the period from 1 January 2023 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. A Risk Management
Framework Performance report is produced and reviewed at each Sustainability
Committee meeting in support of this review.
Near-term and emerging risks
As outlined previously, the Group's RMF is embedded at 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, 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 remain robust
based upon the identified risk profile. It also drives the required
prioritisation of in-depth reviews to be undertaken by the Sustainability
Committee, which are now integrated into the Group's internal audit programme
for review. During the year, five Risk Bowties were reviewed, ensuring that
all 19 of the Group's identified risks have been reviewed within the targeted
cycle.
While not considered an emerging risk, given the focus on climate-related
risks for energy companies, EnQuest has provided further detail below on its
assessment of this risk within the Group's Risk Library. Additional
information can be found in the Group's Task Force on Climate-related
Financial Disclosures.
CLIMATE CHANGE
Risk
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 through
the energy transition and decarbonisation strategy being pursued through the
Infrastructure and New Energy business.
The Group's risk appetite for climate change risk is reported against the
Group's impacted principal risks, while a discrete disclosure against the Task
Force on Climate-related Financial Disclosures can be found on pages 53 to 60.
Mitigation
Mitigations against the Group's principal risks potentially impacted by
climate change are reported later in this report.
The Group has an emissions management strategy and 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
Sustainability Committee of the Board. An emissions reduction of 24% was
achieved over this three-year period through improving operational
performance, minimising flaring and venting where possible, and applying
appropriate and economic improvement initiatives, noting that the ability to
reduce carbon emissions from its own operations will be constrained by the
original design of later-life assets. Following the establishment of the Veri
Energy business in 2023, the Group has further enhanced its business model to
include a focus on repurposing existing infrastructure to support its
renewable energy and decarbonisation ambitions, centred around the Sullom Voe
Terminal.
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's focus on short-cycle investments drives an inherent mitigation
against the potential impact of 'stranded assets'.
Other near-term risks being monitored
Ongoing geopolitical situation
The Group has continued to assess its commercial and IT security arrangements
and does not consider it has a material adverse exposure to the geopolitical
situation with respect to the sanctions imposed on Russia, although recognises
that the situation has caused oil price volatility. The Group continues to
monitor its position to ensure it remains compliant with any sanctions in
place.
FISCAL RISK AND GOVERNMENT TAKE
Unanticipated changes in the regulatory or fiscal environment can affect the
Group's ability to access funding and liquidity. The change to the UK Energy
Profits Levy ('EPL') introduced in the Autumn Budget Statement 2022 materially
impacted the Group's RBL borrowing base and associated amortisation schedule.
In the 2023 Autumn Budget Statement on 22 November, the UK Government
confirmed that they will bring in legislation for the Energy Security
Investment Mechanism and have agreed to index link the trigger floor price to
CPI from April 2024. The Government also announced that once the
decarbonisation allowance of 80% against EPL is withdrawn in March 2028, that
they will replace this with a new allowance at the same effective rate against
the permanent tax regime. Further fiscal changes could be enacted should there
be a change in UK government at the next general election. The Group will
continue to monitor developments and any potential related impacts. The Group
will continue to seek value-accretive opportunities, both through the pursuit
of creative acquisition structures and continued focus on new energy projects.
Note that EPL could also impact the principal risks of Portfolio Concentration
and Financial.
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 at
its February meeting, 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
which of the Group's KPIs could be impacted by this risk (see page 03) for an
explanation of the KPI symbols); and
· An articulation of the Group's risk appetite for each of these principal
risks.
Among 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),
and/or a materially lower than expected production performance for a prolonged
period (see 'Production' risk on pages 20 and 'Subsurface risk and reserves
replacement' on page 23), and/or further changes in the fiscal environment
(see 'Financial' risk on page 21 and 'Fiscal risk and government take' on page
24), which could reduce the Group's cash generation and pace of deleveraging,
which may in turn impact the Company's ability to comply with the requirements
of its debt facilities and/or execute growth opportunities.
Health, SafetY and Environment ('HSE')
Risk
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.
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 2023, EnQuest's Lost Time Incident frequency rate(1) ('LTIF') of 0.52 and
three hydrocarbon releases, reported on page 28, challenged this objective.
The lost time injuries were all associated with routine repetitive tasks
across three assets. The root causes have been assessed and the Group is
working closely with the contractors involved to ensure that everyone is
aligned with EnQuest's safety culture, trained on equipment and procedures and
empowered to stop a task should a safer method be identified. None of the
hydrocarbon releases had common root causes and occurred at three different
locations and, after thorough investigation, no systemic failure was
identified within EnQuest systems.
The incidents occurred in the first part of the year and, since then,
corrective and preventative actions have been implemented, no further LTIs or
hydrocarbon release occurred in the remainder 2023.
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)
Mitigation
The Group's HSE Policy is fully integrated across its operated sites and this
enables a consistent focus on HSE. There is a strong assurance programme in
place to ensure that the Group complies with its policy and principles and
regulatory commitments.
The Group maintains, in conjunction with its core contractors, a comprehensive
programme of assurance activities and has undertaken a series of in-depth
reviews into the Risk Bowties that have demonstrated the robustness of the
management process and identified opportunities for improvement. The
Group-aligned HSE Continuous Improvement Plan promotes a culture of
accountability and performance in relation to HSE matters. The purpose of this
plan is to ensure that everyone understands what is expected of them by having
realistic standards, governance, and capabilities to add value and support the
business. HSE performance is discussed at each Board meeting and the
mitigation of HSE risk continues to be a core responsibility of the
Sustainability Committee. During 2023, 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, PETRONAS Malaysia Petroleum
Management.
Potential impact
Medium (2022 Medium)
Likelihood
Medium (2022 Medium)
Change from last year
Reflecting the hazards associated with oil and gas development and production
in harsh environments, the potential impact has increased albeit the
likelihood of this risk has not changed. Through our HSE processes, there is
continuous focus on the management of the barriers that prevent hazards
occurring. 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 and is achieved by working closely and openly with contractors,
verifiers and regulators to identify potential improvements through an active
assurance process and implement plans to close any gaps in a timely manner.
Risk appetite
Low (2022 Low)
Oil and gas prices
Risk
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.
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 ('RBL') 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
and its assessment of the funds required to support investment in the
development of its resources. The Group will therefore regularly review and
implement suitable programmes to hedge against the possible negative impact of
changes in oil prices within the terms of its established policy (see page 59)
and the terms of the Group's reserve based lending facility, which requires
hedging of EnQuest's entitlement sales volumes (see page 59). From 1 April
2024, the Group had hedged approximately 6.6 MMbbls for 2024 and 2025. This
ensures that the Group will receive a minimum oil price for some of its
production.
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, the Group's focus on production efficiency supports mitigation of a
low oil price environment.
Potential impact
High (2022 High)
Likelihood
High (2022 High)
Change from last year
The potential impact and likelihood remain high, reflecting the uncertain
economic outlook, including possible impacts from a global recession,
geopolitical tensions and associated sanctions, 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.
Risk appetite
Medium (2022 Medium)
PRODUCTION
Risk
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.
Longer‑term production is threatened if low oil prices or prolonged field
shutdowns and/or underperformance requiring high‑cost remediation bring
forward decommissioning timelines.
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.
Potential impact
High (2022 High)
Likelihood
Medium (2022 Medium)
Change from last year
There has been no material change in the potential impact or likelihood. The
Group met its 2023 production guidance and continues to focus on key
maintenance activities during planned shutdowns and procuring a stock of
critical spares to support facility uptime.
Risk appetite
Low (2022 Low)
FINANCIAL
Risk
Inability to fund financial commitments or maintain adequate cash flow and
liquidity and/or reduce costs.
Significant reductions in the oil price, production and/or the funds available
under the Group's reserve based lending ('RBL') facility, and/or further
changes in the UK's fiscal environment, will likely have a material impact on
the Group's ability to repay or refinance its existing credit facilities and
invest in its asset base. 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. Further information is contained in the Financial review,
particularly within the going concern and viability disclosures on pages 15
and 16.
Appetite
The Group remains focused on further reducing its leverage levels, targeting
0.5x EnQuest net debt to EBITDA ratio on a mid-cycle oil price basis,
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 remains a strategic priority. During 2023, the Group's strong
free cash flow generation drove a $236.2 million reduction in EnQuest net debt
to $480.9 million at 31 December 2023, with an EnQuest net debt to adjusted
EBITDA ratio of 0.6x. During the year, EnQuest also entered into a term loan
facility of up to $150 million and repaid its 2023 retail bonds, thus
extending and aligning all debt maturities to 2027. At 27 March 2024, the
Group's RBL facility was undrawn following repayments totalling $140.0 million
in the first quarter of 2024, ensuring the Group remains ahead of the amended
facility amortisation schedule and within its borrowing base limits.
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 and 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.
These steps, together with other mitigating actions available to management,
are expected to provide the Group with sufficient liquidity to meet its
obligations as they fall due.
Potential impact
High (2022 High)
Likelihood
High (2022 High)
Change from last year
There is no change to the potential impact or likelihood. While the Group has
significantly reduced its debt and successfully refinanced its debt facilities
in 2022 and entered into a new term facility in 2023, which extends the
Group's debt maturities to 2027, the imposition of the Energy Profits Levy
('EPL') in the UK has impacted the level of available capital and associated
amortisation schedule under the Group's RBL facility (see the going concern
disclosure on page 15).
Factors such as climate change, other ESG concerns, oil price volatility and
geopolitical risks have impacted investors' and insurers' acceptable levels of
oil and gas sector exposure, with the availability of capital reducing while
the cost of capital has increased. In addition, the cost of emissions trading
allowances may continue to trend upward along with the potential for insurers
to be reluctant to provide surety bonds for decommissioning, thereby requiring
the Group to fund decommissioning security through its balance sheet.
Risk appetite
Medium (2022 Medium)
COMPETITION
Risk
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.
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, which
may include the Group's competitive advantage of $2.0 billion of UK tax
losses, 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.
Potential impact
High (2022 High)
Likelihood
High (2022 High)
Change from last year
The potential impact and likelihood remain unchanged, with the introduction of
the UK EPL likely to impact industry participants' investment views of the UK
North Sea, a number of competitors assessing the acquisition of available oil
and gas assets and the rising potential for consolidation (for example,
through reverse mergers). Operating in a competitive industry may result in
higher than anticipated prices for the acquisition of assets and licences.
Risk appetite
Medium (2022 Medium)
IT SECURITY AND RESILIENCE
Risk
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.
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, Viva Engage posts and poster campaigns.
During 2022, the Audit Committee agreed to update its terms of reference to
highlight its responsibilities more explicitly with regard to the IT control
environment, with the IT controls to be regularly reviewed during meetings.
The Audit Committee also reviewed the Group's cyber-security measures and its
IT resourcing model, noting the Group has a dedicated cyber‑security
manager. Work on assessing the cyber-security environment (including internal
audit reviews) and implementing improvements as necessary has continued during
2023.
Potential impact
Medium (2022 Medium)
Likelihood
High (2022 Medium)
Change from last year
The current geopolitical environment and the increased number of cyber attacks
against companies in the sector in which the Group operates, and beyond,
increases the likelihood of attempted cyber incursions against EnQuest. The
Group continues to evolve its IT systems and resilience to mitigate this.
There is no change to the impact of this risk.
Risk appetite
Low (2022 Low)
PORTFOLIO CONCENTRATION
Risk
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.
Appetite
Although the extent of portfolio concentration is moderated by production
generated in Malaysia, the majority of the Group's assets remain 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.
The Group has made good progress with its decarbonisation strategy,
identifying three key focus areas of carbon capture and storage,
electrification and green hydrogen production through its Infrastructure and
New Energy business, which could provide diversified revenue opportunities in
the long term.
Potential impact
High (2022 High)
Likelihood
High (2022 High)
Change from last year
There has been no material change in the potential impact or likelihood. The
Group is currently focused on oil production and does not have significant
exposure to gas or other sources of income. However, the Group continues to
assess acquisition growth opportunities with a view to improving its asset
diversity over time.
Risk appetite
Medium (2022 Medium)
subsURFAce risk and reserves replacement
Risk
Failure to develop its contingent and prospective resources or secure new
licences and/or asset acquisitions and realise their expected value.
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
workovers, subsea drilling and tie-backs to existing infrastructure.
The Group continues to consider potential opportunities to acquire new
production resources that meet its investment criteria.
Potential impact
High (2022 High)
Likelihood
Medium (2022 Medium)
Change from last year
There has been no material change in the potential impact or likelihood.
Low oil prices, lack of available funds for investment (see 'Financial' risk)
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.
Risk appetite
Medium (2022 Medium)
project execution and delivery
Risk
The Group's success will be partially dependent upon the successful execution
and delivery of potential future projects that are undertaken, including
decommissioning, decarbonisation and new energy opportunities in the UK.
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 and the Decommissioning Projects Delivery Process,
to ensure that deadlines are met, costs are controlled and that design
concepts and Field Development/Decommissioning Plans 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.
Within Veri Energy, the Group is working with experienced third-party
organisations and aims to 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.
Potential impact
Medium (2022 Medium)
Likelihood
Low (2022 Low)
Change from last year
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 decommissioning and Infrastructure and New Energy
projects over an extended period of time.
Risk appetite
Medium (2022 Medium)
fiscal risk and government take
Risk
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.
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 as it
has done throughout the implementation period of the EPL.
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.
Potential impact
High (2022 High)
Likelihood
High (2022 Medium)
Change from last year
There has been no material change in the potential impact; however, the
likelihood has increased given the implementation of, and subsequent change
to, the EPL which will negatively impact free cash flow generation and
therefore the Group's ability to balance further deleveraging and investment
in its asset base.
Risk appetite
Medium (2022 Medium)
international business
Risk
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 (for example, 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.
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.
Potential impact
Medium (2022 Medium)
Likelihood
Medium (2022 Medium)
Change from last year
There has been no material change in the impact or likelihood.
Risk appetite
Medium (2022 Medium)
Joint venture partners
Risk
Failure by joint venture parties to fund their obligations.
Dependence on other parties where the Group is non-operator.
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.
Potential impact
Medium (2022 Medium)
Likelihood
Low (2022 Low)
Change from last year
There has been no material change in the potential impact or likelihood.
Risk appetite
Medium (2022 Medium)
reputation
Risk
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 that EnQuest clearly
articulates its approach to and benchmarks its performance against relevant
and material ESG factors.
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 undertake an annual
anti-bribery and corruption course, an anti‑facilitation of tax evasion
course and a data privacy course.
All personnel are authorised to shut down production for safety-related
reasons.
The Group has a clear ESG strategy, with a focus on health and safety
(including asset integrity), emission 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.
Potential impact
High (2022 High)
Likelihood
Low (2022 Low)
Change from last year
There has been no material change in the potential impact or likelihood.
Risk appetite
Low (2022 Low)
human resources
Risk
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, could also impact the operations of the Group.
Appetite
As a 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 flexible and diverse organisation
require 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 is
therefore 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
each job and that appropriate training, support and development opportunities
are provided, with feedback collated to drive continuous improvement while
delivering SAFE Results.
The culture of the Group is an area of ongoing focus and employee feedback is
frequently sought to understand employees' views on areas, including diversity
and inclusion and wellbeing in order to develop appropriate action plans.
Although it was anticipated that fewer young people may join the industry due
to climate change-related factors, 2023 saw a rise in the number of young
professionals joining EnQuest. We believe the Group's decarbonisation
ambitions as well as the graduate programme, introduced in 2023, has
contributed to this change. EnQuest aims to attract and sustain the best
talent, recognising the value and importance of diversity. The emphasis around
improved diversity in the Group's management and leadership is a main focal
point for the Board. 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.
The Group has reviewed 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, adopting a hybrid approach.
EnQuest has now moved to a 4 - 1 office to work from home ratio to enhance
productivity and motivate staff. The Group will continue to monitor such
practices, adapting as necessary. 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.
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.
Potential impact
Medium (2022 Medium)
Likelihood
Medium (2022 Medium)
Change from last year
There has been no material change to potential impact or likelihood.
Risk appetite
Medium (2022 Medium)
PRODUCTION DETAILS
Average daily production on a net working interest basis 1 Jan 2023 to 1 Jan 2022 to
31 Dec 2023 31 Dec 2022
(Boepd) (Boepd)
UK Upstream
- Magnus 15,933 12,641
- Kraken 13,580 18,394
- Golden Eagle 4,199 6,323
- Other Upstream(1) 2,663 3,443
Total UK 36,375 40,801
Total Malaysia 7,437 6,458
Total EnQuest 43,812 47,259
(1) Other Upstream: Scolty/Crathes, Greater Kittiwake Area and Alba
KEY PERFORMANCE INDICATORS
2023 2022 2021
ESG metrics:
Group LTIF(1) 0.52 0.57 0.21
Emissions (kilo-tonnes of CO(2) equivalent) 1,042.6 1,051.9 1,164.1
Business performance data:
Production (Boepd) 43,812 47,259 44,415
Unit opex (production and transportation costs) ($/Boe)(2) 21.9 22.7 20.5
Cash expenditures ($ million) 211.1 174.8 117.6
Capital(2) 152.2 115.8 51.8
Decommissioning 58.9 59.0 65.8
Reported data:
Cash generated from operations ($ million) 854.7 1,026.1 756.9
EnQuest net debt ($ million)(2) 480.9 717.1 1,222.0
Net 2P reserves (MMboe) 175 190 205
(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 65
OIL AND GAS RESERVES AND RESOURCES
ENQUEST OIL AND GAS RESERVES AND RESOURCES
UKCS Other regions Total
MMboe MMboe MMboe MMboe MMboe
Proven and probable reserves1, 2, 3
At 31 December 2022 160 30 190
Revisions of previous estimates (4) (0)
Transfers from contingent resources4 4 0
0 0 0
Production:
Export meter (13) (3)
Volume adjustments5 0 -
(13) (3) (16)
Total proven and probable reserves at 31 December 20236, 7 147 28 175
Contingent resources(1,) 2, 8, 10
At 31 December 2022 312 81 393
Promoted to reserves9 (4) 0 (4)
Total contingent resources at 31 December 202310 308 81 389
Notes:
1 Opening reserves are quoted on a working interest basis
2 Proven and probable ('2P') reserves and contingent resources ('2C')
have been assessed by the Group's internal reservoir engineers, utilising
geological, geophysical, engineering and financial data
3 The Group's 2P 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. These are based on a different set of forward price
assumptions to those the Group has used for impairment testing resulting in
different economic reserves
4 Transfers from 2C resources at Magnus
5 Correction of export to sales volumes
6 The above 2P reserves include volumes that will be consumed as fuel
gas, including c.6.9 MMboe at Magnus, c.0.8 MMboe at Kraken, c.0.3 MMboe at
Golden Eagle and c.0.1 MMboe at Scolty Crathes
7 The above proven and probable reserves on an entitlement basis are 165
MMboe (UKCS 147 MMboe and other regions 18 MMboe)
8 Contingent resources are quoted on a working interest basis and relate
to technically recoverable hydrocarbons for which commerciality has not yet
been determined and are stated on a best technical case or 2C basis
9 Magnus CoP extension
10 2C contingent resources at 31 December 2023 do not reflect the
transfer of a 15.0% share in the Bressay licence to RockRose that completed in
March 2023
11 Rounding may apply
Group Income Statement
For the year ended 31 December 2023
Notes 2023 2022
Business performance $'000 Remeasurements and exceptional items (note 4) Reported Business performance $'000 Remeasurements and exceptional items (note 4) Reported
$'000 in year $'000 in year
$'000 $'000
Revenue and other operating income 5(a) 1,458,956 28,463 1,487,419 1,839,147 14,475 1,853,622
Cost of sales 5(b) (941,102) (5,650) (946,752) (1,195,806) (4,900) (1,200,706)
Gross profit/(loss) 517,854 22,813 540,667 643,341 9,575 652,916
Net impairment (charge)/reversal 4,10 - (117,396) (117,396) - (81,049) (81,049)
to oil and gas assets
General and administration expenses 5(c) (6,348) - (6,348) (7,553) - (7,553)
Other income 5(d) 17,897 78,984 96,881 76,247 7,706 83,953
Other expenses 5(e) (46,846) (10,731) (57,577) (2,810) (233,570) (236,380)
Profit/(loss) from operations before tax and finance income/(costs) 482,557 (26,330) 456,227 709,225 (297,338) 411,887
Finance costs 6 (172,087) (58,854) (230,941) (176,227) (36,410) (212,637)
Finance income 6 6,493 - 6,493 1,816 2,148 3,964
Profit/(loss) before tax 316,963 (85,184) 231,779 534,814 (331,600) 203,214
Income tax 7 (287,750) 25,138 (262,612) (322,468) 78,020 (244,448)
Profit/(loss) for the year attributable to owners of the parent 29,213 (60,046) (30,833) 212,346 (253,580) (41,234)
Total comprehensive profit/(loss) for the year, attributable to owners of the (30,833) (41,234)
parent
There is no comprehensive income attributable to the shareholders of the Group
other than the profit/(loss) for the period. Revenue and operating
profit/(loss) are all derived from continuing operations.
Earnings per share 8 $ $ $ $
Basic 0.016 (0.016) 0.114 (0.022)
Diluted 0.016 (0.016) 0.112 (0.022)
The attached notes 1 to 31 form part of these Group financial statements.
Group Balance Sheet
At 31 December 2023
Notes 2023 2022
$'000 $'000
ASSETS
Non-current assets
Property, plant and equipment 10 2,296,740 2,476,975
Goodwill 11 134,400 134,400
Intangible assets 12 18,323 45,299
Deferred tax assets 7(c) 540,122 705,808
Other financial assets 19 36,282 6
3,025,867 3,362,488
Current assets
Intangible assets 12 876 1,199
Inventories 13 84,797 76,418
Trade and other receivables 16 225,486 276,363
Current tax receivable 1,858 1,491
Cash and cash equivalents 14 313,572 301,611
Other financial assets 19 113,326 4,705
739,915 661,787
TOTAL ASSETS 3,765,782 4,024,275
EQUITY AND LIABILITIES
Equity
Share capital and premium 20 393,831 392,196
Share-based payments reserve 13,195 11,510
Retained earnings 20 49,702 80,535
TOTAL EQUITY 456,728 484,241
Non-current liabilities
Borrowings 18 283,867 281,422
Bonds 18 463,945 452,386
Lease liabilities 24 288,892 362,966
Contingent consideration 22 461,271 513,677
Provisions 23 715,436 667,335
Deferred income 25 138,416 -
Trade and other payables 17 32,917 -
Deferred tax liabilities 7(c) 77,643 166,334
2,462,387 2,444,120
Current liabilities
Borrowings 18 27,364 131,936
Bonds 18 - 134,544
Lease liabilities 24 133,282 119,100
Contingent consideration 22 46,525 123,198
Provisions 23 79,861 70,335
Trade and other payables 17 347,409 426,647
Other financial liabilities 19 26,679 50,966
Current tax payable 185,547 39,188
846,667 1,095,914
TOTAL LIABILITIES 3,309,054 3,540,034
TOTAL EQUITY AND LIABILITIES 3,765,782 4,024,275
The attached notes 1 to 31 form part of these Group financial statements.
The financial statements were approved by the Board of Directors and
authorised for issue on 27 March 2024 and signed on its behalf by:
Amjad Bseisu
Chief Executive Officer
Group Statement of Changes in Equity
For the year ended 31 December 2023
Notes Share capital and share premium Share-based payments reserve Retained earnings Total
$'000 $'000 $'000 $'000
Balance at 1 January 2022 392,196 6,791 121,769 520,756
Loss for the year - - (41,234) (41,234)
Total comprehensive expense for the year - - (41,234) (41,234)
Share-based payment - 4,719 - 4,719
Balance at 31 December 2022 392,196 11,510 80,535 484,241
Loss for the year - - (30,833) (30,833)
Total comprehensive expense for the year - - (30,833) (30,833)
Issue of shares to Employee Benefit Trust 20 1,635 (1,635) - -
Share-based payment 21 - 3,320 - 3,320
Balance at 31 December 2023 393,831 13,195 49,702 456,728
The attached notes 1 to 31 form part of these Group financial statements.
Group Statement of Cash Flows
For the year ended 31 December 2023
Notes 2023 2022
$'000 $'000
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations 30 854,746 1,026,149
Cash received from insurance 5,190 15,015
Cash (paid)/received on purchase of financial instruments (5,795) (1,354)
Decommissioning spend (58,911) (58,964)
Income taxes paid (40,986) (49,293)
Net cash flows from/(used in) operating activities 754,244 931,553
INVESTING ACTIVITIES
Purchase of property, plant and equipment (141,741) (107,668)
Proceeds from farm-down 25 141,360 -
Vendor financing facility 25 (141,360) -
Purchase of intangible oil and gas assets (10,467) (8,168)
Purchase of other intangible assets 12 (876) (1,199)
Payment of Magnus contingent consideration - Profit share 22 (65,506) (45,975)
Payment of Golden Eagle contingent consideration - Acquisition 22 (50,000) -
Interest received 5,895 1,763
Net cash flows (used in)/from investing activities (262,695) (161,247)
FINANCING ACTIVITIES
Proceeds from loans and borrowings 190,657 87,215
Repayment of loans and borrowings (427,736) (567,020)
Payment of obligations under financing leases 24 (135,675) (147,971)
Interest paid (105,877) (103,387)
Net cash flows (used in)/from financing activities (478,631) (731,163)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS 12,918 39,143
Net foreign exchange on cash and cash equivalents (957) (24,193)
Cash and cash equivalents at 1 January 301,611 286,661
CASH AND CASH EQUIVALENTS AT 31 DECEMBER 313,572 301,611
Reconciliation of cash and cash equivalents
Total cash at bank and in hand 14 313,028 293,866
Restricted cash 14 544 7,745
Cash and cash equivalents per balance sheet 313,572 301,611
The attached notes 1 to 31 form part of these Group financial statements.
Notes to the Group Financial Statements
For the year ended 31 December
2023
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. The address of
the Company's registered office is shown on the inside back cover.
EnQuest PLC is the ultimate controlling party. 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 decarbonisation
opportunities.
The Group's financial statements for the year ended 31 December 2023 were
authorised for issue in accordance with a resolution of the Board of Directors
on 27 March 2024.
A listing of the Group's companies is contained in note 29 to these Group
financial statements.
2. Basis of preparation
The consolidated financial statements have been prepared in accordance with
UK-adopted International Financial Reporting Standards ('IFRS') 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 2023.
The Group financial information has been prepared on a 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 a UK-adopted International Financial Reporting
Standards ('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.
Going concern
The financial statements have been prepared on the going concern basis.
In recent years, given the prevailing macroeconomic and fiscal environment,
the Group has prioritised deleverage - reducing gross debt (excluding leases)
by c.$1.4 billion since 2017 to $794.5 million at 31 December 2023. During
2023, EnQuest net debt was reduced by $236.2 million (to $480.9 million) and
the Group strengthened its net debt to adjusted EBITDA ratio to 0.6x, close to
EnQuest's target of 0.5x. In this 12-month period, cash and available
facilities increased by $149.9 million, to $498.8 million at 31 December 2023,
and medium-term liquidity is secured, with all the Group's debt maturities now
in 2027.
Against this robust backdrop, EnQuest continues to closely monitor and manage
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 Group's latest approved business plan underpins management's base case
('Base Case') and is in line with the Group's production guidance using oil
price assumptions of $80.0/bbl for 2024 and $75.0/bbl for 2025.
A reverse stress test has been performed on the Base Case indicating that an
average oil price of c.$63.0/bbl over the going concern period maintains
covenant compliance, reflecting the Group's strong liquidity position.
The Base Case has also been subjected to further testing through a scenario
reflecting the impact of the following plausible downside risks (the 'Downside
Case'):
· 10% discount to Base Case prices resulting in Downside Case
prices of $72.0/bbl for 2024 and $67.5/bbl for 2025;
· Production risking of 5.0%; and
· 2.5% increase in operating, capital and decommissioning
expenditure.
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.
After making appropriate enquiries and assessing the progress against the
forecast and projections, 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:
· Insurance contracts (IFRS 17)
· Disclosure of Accounting Policies (Amendments to IAS 1 and IFRS
Practice Statement 2)
· Definition of Accounting Estimates (Amendments to IAS 8)
· Deferred Tax related to Assets and Liabilities arising from a
Single Transaction (Amendments to IAS 12)
· International Tax reform - Pillar Two Model Rules (Amendments to
IAS 12)
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 10 and IAS 28 (amendments) Sale or Contribution of Assets between an Investor and its Associate or Joint
Venture
Amendments to IAS 1 Classification of Liabilities as Current or Non-current
Amendments to IAS 1 Non-current Liabilities with Covenants
Amendments to IAS 7 and IFRS 7 Supplier Finance Arrangements
Amendments to IFRS 16 Lease Liability in a Sale and Leaseback
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 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. The Annual Report and Accounts
therefore refers to 'joint ventures' as a standard term 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 2023, the Group did not have any material interests in joint
ventures or in associates as defined in IAS 28.
Foreign currencies
Items included in the financial statements of each of the Group's entities are
measured using the currency of the primary economic environment in which the
entity operates ('functional currency'). The Group's financial statements are
presented in US Dollars, the currency which the Group has elected to use as
its presentation currency.
In the financial statements of the Company and its individual subsidiaries,
transactions in currencies other than a company's functional currency are
recorded at the prevailing rate of exchange on the date of the transaction. At
the year end, monetary assets and liabilities denominated in foreign
currencies are retranslated at the rates of exchange prevailing at the balance
sheet date. Non-monetary assets and liabilities that are measured at
historical cost in a foreign currency are translated using the rate of
exchange at the dates of the initial transactions. Non-monetary assets and
liabilities measured at fair value in a foreign currency are translated using
the rate of exchange at the date the fair value was determined. All foreign
exchange gains and losses are taken to profit and loss in the Group income
statement.
Emissions liabilities
The Group operates in an energy intensive industry and is therefore required
to partake in emission trading schemes ('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. The Group
does not consider contingent consideration and deferred taxation (including
EPL) to represent a significant estimate or judgement as the estimates and
assumptions relating to projected earnings and cash flows used to assess
contingent consideration and deferred taxation are the same as those applied
in the Group impairment process as described below in Recoverability of asset
carrying values. 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 the Group's 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 within the next
financial year 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, cost profile changes
including those related to emission reduction initiatives such as alternative
fuel provision at Kraken, 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. Such estimates reflect management's best estimate of the
related cash flows based on management's plans for the assets and their future
development.
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, life of field production profiles, 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 2023 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. FVLCD 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 2023, the post-tax discount rate was
estimated at 11.0% (2022: 11.0%) with the effect of the Group's reduced debt
position offset by the impact of the general increase in interest rates.
Oil prices
The price assumptions used for FVLCD impairment testing were based on latest
internal forecasts as at 31 December 2023, 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, the Audit Committee and the Board of Directors.
EnQuest revised its oil price assumptions for FVLCD impairment testing
compared to those used in 2022. The Group's long-term price assumption was
increased to better align with external forecasts. 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. They do not correspond to any specific Paris-consistent
scenario, but when compared to the International Energy Agency's ('IEA')
forecast prices under its Announced Pledges Scenario ('APS'), which is
considered to be a scenario achieving an emissions trajectory consistent with
keeping the temperature rise in 2100 below 2°C, could, on average, be
considered to be broadly in line with a Paris-consistent scenario. EnQuest's
short- and medium-term assumptions are below those assumed under the APS,
while its longer-term prices are slightly higher. The impact on the Group from
the forecast prices under the APS are discussed in EnQuest's Task Force on
Climate-related Financial Disclosures report. Discounts or premiums are
applied to price assumptions based on the characteristics of the oil produced
and the terms of the relevant sales contracts.
An inflation rate of 2% (2022: 2%) is applied from 2027 onwards to determine
the price assumptions in nominal terms (see table below). The price
assumptions used in 2022 were $84.0/bbl (2023), $80.0/bbl (2024), $75.0/bbl
(2025) and $70.0/bbl real thereafter, inflated at 2.0% per annum from 2026.
2024 2025 2026 2027>(*)
Brent oil ($/bbl) 80 80 75 77
(· ) (Inflated at 2% from 2027)
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 responsibly optimise production, leverage
existing infrastructure, deliver a strong decommissioning performance and
explore new energy and decarbonisation opportunities. 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 28) 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, which it believes
to be a reasonably possible change given the prevailing macroeconomic
environment.
Price reductions of this magnitude in isolation could indicatively lead to a
further reduction in the carrying amount of EnQuest's oil and gas properties
by approximately $224.1 million, which is approximately 10% of the net book
value of property, plant and equipment as at 31 December 2023.
The oil price sensitivity analysis above does not, however, represent
management's best estimate of any impairments that might be recognised as it
does 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 of 11% used for FVLCD impairment testing of oil and gas
properties, which is considered a reasonably possible change given the
prevailing macroeconomic environment. If the discount rate was one percentage
point higher across all tests performed, the net impairment charge in 2023
would have been approximately $51.3 million higher. If the discount rate was
one percentage point lower, the net impairment charge would have been
approximately $56.0 million lower.
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 (2022: $134.4 million), principally relating to the
acquisition of Magnus oil field. 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
Estimates: Following the rising interest rate environment seen in 2023, the
Group reassessed the fair value discount rate associated with the Magnus
contingent consideration. This was estimated to be 11.3% as at the end of 2023
(2022: 10.0%), as calculated in line with IFRS 13. 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,
although this is not expected within the next year.
The timing and amount of future expenditures relating to decommissioning and
environmental liabilities are reviewed annually. The rate used in discounting
the cash flows is reviewed half-yearly. The nominal discount rate used to
determine the balance sheet obligations at the end of 2023 was 3.5% (2022:
3.5%), reflecting the wider interest rate environment. 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 inflation rates at 2.5% for 2024 and a long-term
inflation rate of 2% thereafter (2022: 4% (2023), 3% (2024) and a long-term
inflation rate of 2% thereafter) to decommissioning costs.
Further information about the Group's provisions is provided in note 23.
Changes in assumptions, including cost reduction factors in relation to the
Group's provisions, could result in a material change in their carrying
amounts within the next financial year. A one percentage point decrease in the
nominal discount rate applied, which is considered a reasonably possible
change given the prevailing macroeconomic environment, could increase the
Group's provision balances by approximately $68.0 million (2022: $54.0
million). The pre-tax impact on the Group income statement would be a charge
of approximately $67.1 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. Refer to note 12 for further details.
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 2023, 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 2023. The North Sea's
activities include Upstream, Midstream, Decommissioning and Veri Energy. Veri
Energy is not considered a separate operating segment as it does not yet earn
revenues and does not yet have material capital and resources. Malaysia's
activities include Upstream and Decommissioning. 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, in line with
IFRS 8 paragraph 23.
Year ended 31 December 2023 North Sea Malaysia All other segments Total segments Adjustments Consolidated
$'000 and
eliminations(i), (ii)
Revenue and other operating income:
Revenue from contracts with customers 1,325,200 142,510 - 1,467,710 - 1,467,710
Other operating income/(expense) 2,229 - 281 2,510 17,199 19,709
Total revenue and other operating income/(expense) 1,327,429 142,510 281 1,470,220 17,199 1,487,419
Income/(expenses) line items:
Depreciation and depletion (278,280) (19,923) (105) (298,308) - (298,308)
Net impairment (charge)/reversal to oil and gas assets (117,396) - - (117,396) - (117,396)
Exploration write-off and impairments - (5,640) - (5,640) - (5,640)
Segment profit/(loss)(ii) 389,355 46,192 4,474 440,021 16,206 456,227
Other disclosures:
Capital expenditure(iii) 149,093 11,817 12 160,922 - 160,922
North Sea Malaysia All other segments Total Adjustments Consolidated
Year ended 31 December 2022 segments and
$'000 eliminations(i), (ii)
Revenue and other operating income:
Revenue from contracts with customers 1,873,214 159,578 - 2,032,792 - 2,032,792
Other operating income/(expense) 9,832 - 264 10,096 (189,266) (179,170)
Total revenue and other operating income/(expense) 1,883,046 159,578 264 2,042,888 (189,266) 1,853,622
Income/(expenses) line items:
Depreciation and depletion (319,025) (14,116) (107) (333,248) - (333,248)
Net impairment (charge)/reversal to oil and gas assets (81,049) - - (81,049) - (81,049)
Segment profit/(loss)(ii) 546,199 65,160 112 611,471 (199,584) 411,887
Other disclosures:
Capital expenditure(iii) 115,853 39,030 30 154,913 - 154,913
(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
Reconciliation of profit/(loss):
Year ended Year ended
31 December 31 December
2023 2022
$'000 $'000
Segment profit/(loss) before tax and finance income/(costs) 440,021 611,471
Finance costs (230,941) (212,637)
Finance income 6,493 3,964
Gain/(loss) on oil and foreign exchange derivatives(i) 16,206 (199,584)
Profit/(loss) before tax 231,779 203,214
(i) Includes $8.4 million realised losses on derivatives (2022: $209.2
million) and $24.6 million unrealised gains on derivatives (2022: $9.6
million)
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 $491.2 million and $201.3 million per each single
customer (2022: two customers; $365.1 million and $321.7 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 2023 Fair value Impairments Other((iii)) Total
$'000 remeasurement((i)) and write-offs((ii))
Revenue and other operating income 28,463 - - 28,463
Cost of sales (3,832) - (1,818) (5,650)
Net impairment (charge)/reversal on oil and gas assets - (117,396) - (117,396)
Other income 69,665 - 9,319 78,984
Other expense - (5,640) (5,091) (10,731)
Finance costs - - (58,854) (58,854)
94,296 (123,036) (56,444) (85,184)
Corporation tax on items above (37,788) 181 21,790 (15,817)
UK Energy Profits Levy (38,560) 22,518 56,997 40,955
17,948 (100,337) 22,343 (60,046)
4. Remeasurements and exceptional items continued
Year ended 31 December 2022 Fair value Impairments Other((iii)) Total
$'000 remeasurement((i)) and write-offs((ii))
Revenue and other operating income 14,475 - - 14,475
Cost of sales (4,900) - - (4,900)
Net impairment (charge)/reversal on oil and gas assets - (81,049) - (81,049)
Other income 1,070 - 6,636 7,706
Other expenses (233,570) - - (233,570)
Finance costs - - (36,410) (36,410)
Finance income - - 2,148 2,148
(222,925) (81,049) (27,626) (331,600)
Corporation tax on items above 89,599 32,420 7,817 129,836
Recognition of undiscounted deferred tax asset(iv) - 127,024 - 127,024
UK Energy Profits Levy(v) - - (178,840) (178,840)
(133,326) 78,395 (198,649) (253,581)
(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 $24.6 million (2022:
$9.6 million). Other income relates to the fair value remeasurement of
contingent consideration relating to the acquisition of Magnus and associated
infrastructure of $69.7 million (note 22) (2022: net other expense of $232.5
million)
(ii) Impairments and write-offs include a net impairment charge of tangible
oil and gas assets and right-of-use assets totalling $117.4 million (note 10)
(2022: charge of $81.0 million) and write-off of exploration costs in Malaysia
of $5.6 million (2022: nil)
(iii) Other items are made up of the following: other costs of sales includes
$1.8 million related to an increase in a provision for a dispute with a
third-party contractor (2022: nil). Other net income primarily includes $4.1
million recognition of insurance income related to the PM8/Seligi riser
incident (2022: $6.6 million) and $0.1 million movement in other provisions
(2022: nil). Finance costs relates to the finance cost element of the 75%
acquisition of Magnus and associated infrastructure of $58.9 million (note 22)
(2022: $36.4 million). In 2022, finance income of $2.1 million represents a
realised gain on the partial buy back of the Group's 7.00% high yield bond
(iv) Non-cash deferred tax recognition in 2022 is due to the Group's higher
oil price assumptions
(v) In 2022, UK Energy Profits Levy ('EPL') represented the charge on initial
recognition. In 2023, the related assumptions were refined, resulting in a
credit of $32.7 million in other items. The remaining EPL items relate to the
EPL charges and credits on the items above
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 operating revenue 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, rather are accounted for in line with IFRS 9 and included within
other operating income (see note 19).
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000
Revenue from contracts with customers:
Revenue from crude oil sales 1,127,419 1,517,666
Revenue from gas and condensate sales(i) 338,973 514,206
Tariff revenue 1,318 920
Total revenue from contracts with customers 1,467,710 2,032,792
Realised gains/(losses) on oil derivative contracts (see note 19) (11,264) (203,741)
Other 2,510 10,096
Business performance revenue and other operating income 1,458,956 1,839,147
Unrealised gains/(losses) on oil derivative contracts(ii) (see note 19) 28,463 14,475
Total revenue and other operating income 1,487,419 1,853,622
(i) Includes onward sale of third-party gas purchases not required for
injection activities at Magnus (see note 5(b))
(ii) Unrealised gains and losses on oil derivative contracts are disclosed
as fair value remeasurement items in the income statement (see note 4)
Disaggregation of revenue from contracts with customers
Year ended Year ended
31 December 2023 31 December 2022
$'000 $'000
North Sea Malaysia Total North Sea Malaysia Total
Revenue from contracts with customers:
Revenue from crude oil sales 987,610 139,809 1,127,419 1,360,228 157,438 1,517,666
Revenue from gas and condensate sales(i) 336,902 2,071 338,973 512,066 2,140 514,206
Tariff revenue 689 629 1,318 920 - 920
Total revenue from contracts with customers 1,325,201 142,509 1,467,710 1,873,214 159,578 2,032,792
(i) Includes onward sale of third-party gas purchases not required for
injection activities at Magnus (see note 5(b))
(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 ('NRV'),
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 31 December 2023 Year ended 31 December 2022
$'000 $'000
Production costs 308,331 347,832
Tariff and transportation expenses 41,736 43,266
Realised (gain)/loss on derivative contracts related to operating costs (see (2,839) 5,418
note 19)
Change in lifting position (2,669) (18,790)
Crude oil inventory movement (1,575) 3,222
Depletion of oil and gas assets(i) 292,199 327,027
Other cost of operations(ii) 305,919 487,831
Business performance cost of sales 941,102 1,195,806
Unrealised losses/(gains) on derivative contracts related to operating 3,832 4,900
costs(iii) (see note 19)
Movement in contractor dispute provision (see note 23) 1,818 -
Total cost of sales 946,752 1,200,706
(i) Includes $28.6 million (2022: $38.7 million) Kraken FPSO right-of-use
asset depreciation charge and $24.0 million (2022: $15.8 million) of other
right-of-use assets depreciation charge
(ii) Includes $294.0 million (2022: $452.8 million) of purchases and
associated costs 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 31 December 2023 Year ended 31 December 2022
$'000 $'000
Staff costs (see note 5(f)) 77,517 75,266
Depreciation(i) 6,109 6,222
Other general and administration costs 25,490 21,740
Recharge of costs to operations and joint venture partners (102,768) (95,675)
Total general and administration expenses 6,348 7,553
(i) Includes $3.4 million (2022: $3.4 million) right-of-use assets
depreciation charge on buildings
(d) Other income
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000
Net foreign exchange gains - 21,329
Change in decommissioning provisions (see note 23) - 36,763
Change in Thistle decommissioning provisions (see note 23) - 6,060
Rental income from office sublease 2,286 1,549
Other 15,611 10,546
Business performance other income 17,897 76,247
Fair value changes in contingent consideration (see note 22) 69,665 1,070
Other non-business performance (see note 4) 9,319 6,636
Total other income 96,881 83,953
(e) Other expenses
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000
Net foreign exchange losses 11,659 -
Change in decommissioning provisions (see note 23) 31,159 -
Change in Thistle decommissioning provisions (see note 23) 1,605 -
Other 2,423 2,810
Business performance other expenses 46,846 2,810
Fair value changes in contingent consideration (see note 22) - 233,570
Other non-business performance (see note 4) 10,731 -
Total other expenses 57,577 236,380
(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 31 December 2023 Year ended 31 December 2022
$'000 $'000
Wages and salaries 63,458 63,430
Social security costs 5,457 6,547
Defined contribution pension costs 5,038 4,968
Expense of share-based payments (see note 21) 3,320 4,719
Other staff costs 11,079 12,984
Total employee costs 88,352 92,648
Contractor costs 38,304 33,661
Total staff costs 126,656 126,309
General and administration staff costs (see note 5(c)) 77,517 75,266
Non-general and administration costs 49,139 51,043
Total staff costs 126,656 126,309
The monthly average number of persons, excluding contractors, employed by the
Group during the year was 697, with 343 in the general and administration
staff costs and 354 directly attributable to assets (2022: 715 of which 335 in
general and administration and 380 directly attributable to assets).
Compensation of key management personnel is disclosed in note 26 and in the
Directors' Remuneration Report.
(g) Auditor's remuneration
The following amounts for the year ended 31 December 2023 and for the
comparative year ended 31 December 2022 were payable by the Group to Deloitte:
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000
Fees payable to the Company's auditor for the audit of the parent company and 1,239 1,064
Group financial statements
The audit of the Company's subsidiaries 177 274
Total audit 1,416 1,338
Audit-related assurance services(i) 314 649
Total audit and audit-related assurance services 1,730 1,987
Total auditor's remuneration 1,730 1,987
(i) Audit-related assurance services in both years include the review of the
Group's interim results, G&A assurance review and the Bond refinancing
activities
6. Finance costs/income
Accounting policy
Borrowing costs are recognised as interest payable within finance costs at
amortised cost using the effective interest method.
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000
Finance costs:
Loan interest payable 30,708 14,906
Bond interest payable 58,999 62,260
Unwinding of discount on decommissioning provisions (see note 23) 24,236 16,995
Unwinding of discount on other provisions (see note 23) 1,145 777
Finance charges payable under leases (see note 24) 43,801 39,172
Amortisation of finance fees on loans and bonds 7,899 35,287
Other financial expenses(i) 5,299 6,830
Business performance finance expenses 172,087 176,227
Unwinding of discount on Magnus-related contingent consideration (see note 22) 58,854 36,410
Total finance costs 230,941 212,637
Finance income:
Bank interest receivable 6,493 1,816
Business performance finance income 6,493 1,816
Other financial income (see note 4) - 2,148
Total finance income 6,493 3,964
(i) Includes unwinding of discount on Golden Eagle contingent consideration
of $1.7 million (2022: $3.2 million). See note 22
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 a
temporary difference arises from initial recognition of other assets or
liabilities 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.
Energy Profits Levy
The Energy (Oil & Gas) Profits Levy Act 2022 ('EPL') applies an additional
tax on the profits earned by oil and gas companies from the production of oil
and gas on the United Kingdom Continental Shelf until 31 March 2028 (see note
7(e) for extension to 31 March 2029). This 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 UK companies. Current and deferred tax is provided on
the same basis as described above for income taxes.
The major components of income tax expense/(credit) are as follows:
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000
Current UK income tax
Current income tax charge - -
Adjustments in respect of current income tax of previous years (14) (243)
Current overseas income tax
Current income tax charge 24,685 19,017
Adjustments in respect of current income tax of previous years (2,567) (6,551)
UK Energy Profits Levy
Current year charge 175,118 72,147
Adjustments in respect of current charge of previous years (11,605) -
Total current income tax 185,617 84,370
Deferred UK income tax
Relating to origination and reversal of temporary differences 160,712 1,784
Adjustments in respect of changes in tax rates - 45
Adjustments in respect of deferred income tax of previous years 4,974 (4,668)
Deferred overseas income tax
Relating to origination and reversal of temporary differences (3,761) 6,884
Adjustments in respect of deferred income tax of previous years 1,430 2,363
Deferred UK Energy Profits Levy
Relating to origination and reversal of temporary differences (58,661) 153,670
Adjustments in respect of deferred charge of previous years (27,699) -
Total deferred income tax 76,995 160,078
Income tax expense reported in profit or loss 262,612 244,448
(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
2023 2022
$'000 $'000
Profit/(loss) before tax 231,779 203,214
UK statutory tax rate applying to North Sea oil and gas activities of 40% 92,712 81,284
(2022: 40%)
Supplementary corporation tax non-deductible expenditure 10,580 11,486
Non-deductible expenditure(i) 69,494 47,951
Petroleum revenue tax (net of income tax benefit) (8,200) -
Tax in respect of non-ring-fence trade 7,418 8,892
Deferred tax asset impairment in respect of non-ring-fence trade 11,696 8,563
Deferred tax asset recognition in respect of ring-fence trade - (127,022)
UK Energy Profits Levy(ii) 116,457 225,817
Adjustments in respect of prior years (35,481) (9,098)
Overseas tax rate differences (1,114) (1,264)
Share-based payments (90) (1,345)
Other differences (860) (816)
At the effective income tax rate of 113% (2022: 120%) 262,612 244,448
(i) Predominantly in relation to non-qualifying expenditure relating to the
initial recognition exemption utilised under IAS 12 upon acquisition of Golden
Eagle given that at the time of the transaction, it affected neither
accounting profit nor taxable profit
(ii) Includes current EPL charge of $175.1 million (2022: $72.1 million
charge) and deferred EPL credit of $58.7 million (2022: $153.7 million charge)
(c) Deferred income tax
Deferred income tax relates to the following:
Group balance sheet Charge/(credit) for the year recognised in profit or loss
2023 2022 2023 2022
$'000 $'000 $'000 $'000
Deferred tax liability
Accelerated capital allowances 877,800 963,816 (86,015) 195,185
877,800 963,816
Deferred tax asset
Losses (695,888) (902,101) 206,213 114,996
Decommissioning liability (265,800) (238,624) (27,176) 47,421
Other temporary differences (378,592) (362,565) (16,027) (197,524)
(1,340,280) (1,503,290) 76,995 160,078
Net deferred tax (assets) (462,479) (539,474)
Reflected in the balance sheet as follows:
Deferred tax assets (540,122) (705,808)
Deferred tax liabilities 77,643 166,334
Net deferred tax (assets) (462,479) (539,474)
Reconciliation of net deferred tax assets/(liabilities)
2023 2022
$'000 $'000
At 1 January 539,474 699,552
Tax expense during the period recognised in profit or loss (76,995) (160,078)
At 31 December 462,479 539,474
(d) Tax losses
The Group's deferred tax assets at 31 December 2023 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. 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 $62.5 million while a
10% increase in oil price would not result in any change as the Group is
currently recognising all UK tax losses (with the exception of those noted
below).
The Group has unused UK mainstream corporation tax losses of $442.1 million
(2022: $389.7 million) and ring-fence tax losses of $1,163.0 million (2022:
$1,163.0 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 $8.5 million (2022: $10.7 million) remaining
unrecognised.
The Group has unused Malaysian income tax losses of $14.3 million (2022: $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
Finance Act 2001 amended the mainstream corporation tax rate to 25% from 1
April 2023. The change had no impact in the current year as UK mainstream
corporation tax losses are not recognised.
In the Autumn Statement on 22 November 2023, the UK Government confirmed that
it will bring in legislation for the Energy Security Investment Mechanism and
has agreed to index link the trigger floor price to the CPI from April 2024.
The Government also announced that once the decarbonisation allowance of 80%
against EPL is withdrawn in March 2028, it will replace this with a new
allowance at the same effective rate against the permanent tax regime. In
March 2024, the UK Government announced that the sunset clause for EPL would
be extended by a year to 31 March 2029, the impact on the current year
financial statements would be an increase in the tax charge and deferred tax
for EPL by $44.6 million. The Group will continue to monitor developments and
any potential related impacts.
The UK has introduced legislation implementing the Organisation for Economic
Co-operation and Development's ('OECD') proposals for a global minimum
corporation tax rate (Pillar Two) which is effective for periods beginning on
or after 31 December 2023. This legislation will ensure that profits earned
internationally are subject to a minimum tax rate of 15%. The Group has
performed an assessment of the potential exposure to Pillar Two income taxes
from 1 January 2024 and as the only material overseas jurisdiction in which
the Group operates is Malaysia, which is subject to a tax rate of 38%, the
Group does not expect a material exposure to Pillar Two income taxes in any
jurisdictions. The Group has applied the mandatory exception to recognising
and disclosing information about the deferred tax assets and liabilities
related to Pillar Two income taxes in accordance with the amendments to IAS 12
published by the International Accounting Standards Board ('IASB') on 23 May
2023.
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) Weighted average number of Ordinary shares Earnings
after tax per share
Year ended 31 December Year ended 31 December Ye
ar
en
de
d
31
De
ce
mb
er
2023 2022 2023 2022 2023 2022
$'000 $'000 million million $ $
Basic (30,833) (41,234) 1,871.9 1,855.0 (0.016) (0.022)
Dilutive potential of Ordinary shares granted under share-based incentive - - 4.9 39.2 - -
schemes
Diluted(i) (30,833) (41,234) 1,876.8 1,894.2 (0.016) (0.022)
Basic (excluding remeasurements and exceptional items) 29,213 212,346 1,871.9 1,855.0 0.016 0.114
Diluted (excluding remeasurements and exceptional items)(i) 29,213 212,346 1,876.8 1,894.2 0.016 0.112
(i) Potential Ordinary shares are not treated as dilutive when they would
decrease a loss per share
9. Distributions paid and proposed
The Company paid no dividends during the year ended 31 December 2023 (2022:
none). At 31 December 2023, there are no proposed dividends (2022: none).
The Board of Directors of EnQuest PLC are proposing making a $15.0 million
share buy back, to be executed during 2024. The distribution will be below
the limit granted at the 2023 Annual General Meeting allowing the Company to
purchase up to 10% of its issued Ordinary share capital in the market.
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, 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 for each CGU. The life of a field depends on
the interaction of a number of variables; see note 2 for further details.
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 and gas assets Office furniture, fixtures and fittings Right-of- Total
$'000 $'000 use assets $'000
(note 24)
$'000
Cost:
At 1 January 2022 8,997,353 65,385 867,893 9,930,631
Additions 116,415 1,936 28,394 146,745
Change in decommissioning provision (75,917) - - (75,917)
Disposal - - (19,428) (19,428)
At 1 January 2023 9,037,851 67,321 876,859 9,982,031
Additions 120,820 1,257 28,378 150,455
Change in decommissioning provision (note 23) 53,333 - - 53,333
Disposal - - (243) (243)
Reclassification from intangible assets (note 12) 31,803 - - 31,803
At 31 December 2023 9,243,807 68,578 904,994 10,217,379
Accumulated depreciation, depletion and impairment:
At 1 January 2022 6,650,304 53,829 404,500 7,108,633
Charge for the year 272,588 2,796 57,864 333,248
Net impairment charge for the year 78,058 - 2,991 81,049
Disposal - - (17,874) (17,874)
At 1 January 2023 7,000,950 56,625 447,481 7,505,056
Charge for the year 239,640 2,689 55,979 298,308
Net impairment charge/(reversal) for the year 123,473 - (6,077) 117,396
Disposal - - (121) (121)
At 31 December 2023 7,364,063 59,314 497,262 7,920,639
Net carrying amount:
At 31 December 2023 1,879,744 9,264 407,732 2,296,740
At 31 December 2022 2,036,901 10,696 429,378 2,476,975
At 1 January 2022 2,347,049 11,556 463,393 2,821,998
The amount of borrowing costs capitalised during the year ended 31 December
2023 was nil (2022: nil), reflecting the short-term nature of the Group's
capital expenditure programmes.
Impairments
Impairments to the Group's producing assets and reversals of impairments are
set out in the table below:
Impairment Recoverable
reversal/(charge) amount(i)
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000 31 December 2023 31 December 2022
$'000 $'000
North Sea (117,396) (81,049) 1,323,009 1,448,391
Net pre-tax impairment reversal/(charge) (117,396) (81,049)
(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, along with sensitivity analysis, see Use of judgements, estimates
and assumptions: recoverability of asset carrying values within note 2.
The 2023 net impairment charge of $117.4 million relates to producing assets
in the UK North Sea. Impairment charges/reversals were primarily driven by
changes in production and cost profile updates on non-operated assets,
partially offset by higher forecast oil prices. The 2022 net impairment charge
was primarily driven by the introduction of EPL, changes in production
profiles and an increased discount rate partially offset by an increase in
EnQuest's oil price assumptions.
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:
2023 2022
$'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, relates to the 75% acquisition of the Magnus oil
field and associated interests. The remaining balance relates to the
acquisition of the GKA and Scolty Crathes fields.
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. See notes 2 and 10 for further details. An
impairment charge of nil was taken in 2023 (2022: 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 assumptions, 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 not result in an impairment charge (2022: 10%
reduction would not result in an impairment charge). A 20% reduction in oil
price would fully impair goodwill (2022: 25%).
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 2023, there was no impairment of historical
exploration and appraisal expenditures (2022: nil), although $31.8 million of
intangible assets associated with the Kraken field were transferred to
property, plant and equipment, reflecting updated drilling plans following
assessment of previous seismic survey information. During 2023, Malaysia
drilled an exploration well on the PM409 licence. The results indicated that
there were no commercial prospects and as a result costs of $5.6 million have
been written off through the income statement.
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 $'000 Total
$'000 $'000
Cost:
At 1 January 2022 172,381 10,052 182,433
Additions 8,168 1,199 9,367
Write-off of relinquished licences previously impaired (25,612) - (25,612)
Disposal - (10,052) (10,052)
At 1 January 2023 154,937 1,199 156,136
Additions 10,467 876 11,343
Write-off of relinquished licences previously impaired (485) - (485)
Write-off of unsuccessful exploration expenditure (5,640) - (5,640)
Transfer to property, plant and equipment (note 10) (31,803) - (31,803)
Disposal - (1,199) (1,199)
At 31 December 2023 127,476 876 128,352
Accumulated impairment:
At 1 January 2022 (134,766) - (134,766)
Write-off of relinquished licences previously impaired 25,128 - 25,128
At 1 January 2023 (109,638) - (109,638)
Write-off of relinquished licences previously impaired 485 - 485
At 31 December 2023 (109,153) - (109,153)
Net carrying amount:
At 31 December 2023 18,323 876 19,199
At 31 December 2022 45,299 1,199 46,498
At 1 January 2022 37,615 10,052 47,667
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.
2023 2022
$'000 $'000
Hydrocarbon inventories 21,189 19,613
Well supplies 63,608 56,805
84,797 76,418
During 2023, a net gain of $2.2 million was recognised within cost of sales in
the Group income statement relating to inventory (2022: net loss of $4.0
million). The $8.4 million increase in well supplies was primarily driven by
increased drilling activities.
The inventory valuation at 31 December 2023 is stated net of a provision of
$36.3 million (2022: $38.9 million) to write-down well supplies to their
estimated net realisable value.
Inventory with a net book value of $2.9 million was sold as part of the
Bressay farm-down (note 25).
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.
2023 2022
$'000 $'000
Available cash 313,028 293,866
Restricted cash 544 7,745
Cash and cash equivalents 313,572 301,611
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 2023 is restricted cash of
$0.5 million placed on deposit in relation to bank guarantees for the Group's
Malaysian assets (31 December 2022: $7.7 million).
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 loss allowance 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 FVPL.
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 FVPL
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 28. 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.
Financial assets with cash flows that are not solely payments of principal and
interest are classified and measured at FVPL, 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 2023 Notes Total Quoted prices in active markets (Level 1) $'000 Significant observable inputs Significant unobservable inputs
$'000 (Level 2) (Level 3)
$'000 $'000
Amortised cost
$'000
Financial assets measured at fair value:
Derivative financial assets measured at FVPL
Gas commodity contracts 19(a) 4,499 - - 4,499 -
Other financial assets measured at FVPL
Quoted equity shares 6 - 6 - -
Total financial assets measured at fair value 4,505 - 6 4,499 -
Financial assets measured at amortised cost:
Vendor financing facility 19(f) 145,103 145,103 - - -
Total financial assets measured at amortised cost((ii)) 145,103 145,103 - - -
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Oil commodity derivative contracts 19(a) 18,418 - - 18,418 -
Forward UKA contracts 19(a) 8,261 - - 8,261 -
Other financial liabilities measured at FVPL
Contingent consideration 22 507,796 - - - 507,796
Total liabilities measured at fair value 534,475 - - 26,679 507,796
Liabilities measured at amortised cost
Interest-bearing loans and borrowings((ii)) 18(a) 319,784 319,784 - - -
Retail bond 9.00% 18(b) 158,683 - 158,683 - -
High yield bond 11.625% 18(b) 292,419 - 292,419 - -
Total liabilities measured at amortised cost((i)) 770,886 319,784 451,102 - -
((i)) Excludes related fees
((ii)) Amortised cost is a reasonable approximation of the fair value
31 December 2022 Notes Total Quoted prices in active markets Significant observable inputs Significant unobservable inputs
$'000 (Level 1) (Level 2) (Level 3)
$'000 $'000 $'000
Amortised cost $'000
Financial assets measured at fair value:
Derivative financial assets measured at FVPL
Gas commodity contracts 4,705 - - 4,705 -
Other financial assets measured at FVPL
Quoted equity shares 6 - 6 - -
Total financial assets measured at fair value 4,711 - 6 4,705 -
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Oil commodity derivative contracts 19(a) 46,537 - - 46,537 -
Forward UKA contracts 19(a) 4,429 - - 4,429 -
Other financial liabilities measured at FVPL
Contingent consideration 22 636,875 - - - 636,875
Total liabilities measured at fair value 687,841 - - 50,966 636,875
Liabilities measured at amortised cost:
Interest-bearing loans and borrowings((ii)) 18(a) 417,967 417,967 - - -
Retail bond 7.00% 18(b) 133,535 - 133,535 - -
Retail bond 9.00% 18(b) 153,754 - 153,754 - -
High yield bond 11.625% 18(b) 297,528 - 297,528 - -
Total liabilities measured at amortised cost((i)) 1,002,784 417,967 584,817 - -
( )
((i)) Excludes related fees
((ii)) Amortised cost is a reasonable approximation of the fair value
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. prices) or
indirectly (i.e. derived from prices) observable; and
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, details of which and a reconciliation of movements are
disclosed in note 22. There have been no transfers between Level 1 and Level 2
during the period (2022: no transfers).
For the financial assets and 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, while interest-bearing loans and borrowings and the vendor
financing facility were calculated at amortised cost using the effective
interest method to capture the present value (Level 3). A reconciliation of
movements is disclosed in note 30.
16. Trade and other receivables
2023 2022
$'000 $'000
Current
Trade receivables 31,905 69,508
Joint venture receivables 79,036 95,854
Under-lift position 22,309 26,474
VAT receivable 3,314 -
Other receivables 3,715 4,141
Prepayments 2,781 1,271
Accrued income 82,426 79,115
225,486 276,363
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 2023 or 2022.
17. Trade and other payables
2023 2022
$'000 $'000
Current
Trade payables 75,981 82,897
Accrued expenses 228,664 300,317
Over-lift position 18,824 25,658
Joint venture creditors 20,262 11,957
VAT payable - 5,282
Other payables 3,678 536
Total Current 347,409 426,647
Non-current
Joint venture creditors 32,917 -
Total Non-current 32,917 -
The carrying value of the Group's current 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.
The carrying value of the Group's non-current trade and other payables as
stated above is considered to be a reasonable approximation to their fair
value as this is a specific bi-lateral agreement between counterparties with
the liability extinguished in full over time in accordance with the agreed
schedule.
18. Loans and borrowings
2023 2022
$'000 $'000
Borrowings 311,231 413,358
Bonds 463,945 586,930
775,176 1,000,288
(a) Borrowings
The Group's borrowings are carried at amortised cost as follows:
2023 2022
Principal $'000 Fees Total Principal Fees Total
$'000
$'000 $'000 $'000 $'000
RBL facility 140,000 (4,920) 135,080 400,000 (4,609) 395,391
Term Loan facility 150,000 (3,633) 146,367 - - -
SVT working capital facility 29,784 - 29,784 12,275 - 12,275
Vendor loan facility - - - 5,692 - 5,692
Total borrowings 319,784 (8,553) 311,231 417,967 (4,609) 413,358
Due within one year 27,364 131,936
Due after more than one year 283,867 281,422
Total borrowings 311,231 413,358
See liquidity risk - note 28 for the timing of cash outflows relating to loans
and borrowings.
Reserve Based Lending facility ('RBL')
In October 2022, the Group agreed an amended and restated RBL facility with
commitments of $500.0 million, reducing in accordance with an amortisation
schedule, a sub limit for drawings in the form of Letters of Credit of $75.0
million and a standard accordion facility which allowed the Group to increase
commitments by an amount of up to $300.0 million on no more than three
occasions. The maturity of the new facility is April 2027. Funds can only be
drawn under the RBL to a maximum amount of the lesser of (i) the total
commitments and (ii) the borrowing base amount. Interest accrues at 4.00% plus
a combination of an agreed credit adjustment spread and Secured Overnight
Financing Rate ('SOFR').
As at 31 December 2023, the carrying value of the facility was $135.1 million
(2022: $395.4 million), comprising the principal of $140.0 million out of
accessible commitments of $309.0 million (2022: $400.0 million out of
commitments of $500.0 million) and unamortised fees of $4.9 million (2022:
$4.6 million).
At 31 December 2023, $166.2 million (2022: $47.3 million) remained available
for drawdown under the RBL. By the end of February 2024, the Group had fully
repaid the outstanding $140.0 million of its drawn Reserve Based Lending
Facility.
At 31 December 2023, the Letter of Credit utilisation was $43.5 million (2022:
$52.7 million).
Term Loan facility
In August 2023, the Group agreed a second lien US Dollar Term Loan facility of
$150.0 million. This facility, which was drawn down in full in September 2023,
matures in July 2027 and incurs interest at SOFR +7.90%. As at 31 December
2023, the carrying amount of the facility was $146.4 million (2022: nil),
comprising the principal of $150.0 million and unamortised fees of $3.6
million. See note 27.
SVT working capital facility
EnQuest has extended the £42.0 million revolving loan facility with a joint
operator partner to fund the short-term working capital cash requirements of
SVT and associated interests until April 2024. Agreements to transfer the
facility to a replacement bank are expected to be executed in April 2024. The
facility is guaranteed by BP EOC Limited until the earlier of: a) the date on
which production from Magnus permanently ceases; or b) if the operating
agreements for both SVT and associated infrastructure are amended to allow for
cash calling. The facility is able to be drawn down against, in instalments,
and accrues interest at 1.0% per annum plus GBP Sterling Over Night Index
Average ('SONIA').
Vendor Loan facility
In June 2023, the Group agreed an amended and restated facility with a
third-party vendor providing capacity for refinancing the payment of existing
invoices up to an amount of £15.0 million, with interest payable monthly at a
rate of 9.00% per annum. At 31 December 2023, nil was drawn down on the
facility and so this facility expired on 1 January 2024 in accordance with the
terms of the facility.
In December 2022, the Group agreed a facility with a third-party vendor
refinancing the payment of existing invoices up to an amount of £7.5 million.
At 31 December 2022, £4.7 million was drawn down. This amount was fully
repaid in May 2023. Interest was payable monthly at a rate of 8.00% per annum.
(b) Bonds
The Group's bonds are carried at amortised cost as follows:
2023 2022
Principal $'000 Fees and discount Total Principal Fees and discount Total
$'000 $'000 $'000 $'000 $'000
High yield bond 11.625% 305,000 (10,724) 294,276 305,000 (13,815) 291,185
Retail bond 7.00% - - - 134,544 - 134,544
Retail bond 9.00% 169,669 - 169,669 161,201 - 161,201
Total 474,669 (10,724) 463,945 600,745 (13,815) 586,930
Due within one year - 134,544
Due after more than one year 463,945 452,386
Total 463,945 586,930
High yield bond 11.625%
In October 2022, the Group concluded an offer of $305.0 million for a US
Dollar high yield bond. The notes accrue a fixed coupon of 11.625% payable
semi-annually in arrears with a maturity date of November 2027.
The above carrying value of the bond as at 31 December 2023 is $294.3 million
(2022: $291.2 million). This includes bond principal of $305.0 million (2022:
$305.0 million) less the unamortised original issue discount ('OID') of $3.3
million (2022: $4.2 million) and unamortised fees of $7.4 million (2022: $9.6
million). The high yield bond does not include accrued interest of $5.8
million (2022: $6.5 million), which is reported within trade and other
payables. The fair value of the high yield bond is disclosed in note 15.
Retail bond 7.00%
On 27 April 2022, following a successful partial exchange and cash offer,
£79.3 million of the retail bond 7.00% were exchanged for the retail bond
9.00%. This resulted in an outstanding principal of £111.3 million. On 13
October 2023, the outstanding principal of £111.3 million was repaid in full.
Retail bond 9.00%
On 27 April 2022, the Group issued a new 9.00% retail bond following a
successful partial exchange and cash offer. The principal of the retail bond
9.00% raised by the partial exchange and cash offer totalled £133.3 million.
The notes accrue a fixed coupon of 9.00% payable semi-annually in arrears and
are due to mature in October 2027.
The above carrying value of the bond as at 31 December 2023 is $169.7 million
(2022: $161.2 million). All fees associated with this offer were recognised in
the income statement in 2022. The retail bond 9.00% does not include accrued
interest of $2.7 million (2022: $2.6 million), which is reported within trade
and other payables. The fair value of the retail bond 9.00% is disclosed in
note 15.
19. Other financial assets and financial liabilities
(a) Summary as at year end
2023 2022
Assets Liabilities $'000 Assets Liabilities $'000
$'000
$'000
Fair value through profit or loss:
Derivative commodity contracts 4,499 18,418 4,705 46,537
Derivative UKA contracts - 8,261 - 4,429
Amortised cost:
Other receivables (Vendor financing facility) (notes 19(f), 25((i)) ) 108,827 - - -
Total current 113,326 26,679 4,705 50,966
Fair value through profit or loss:
Quoted equity shares 6 - 6 -
Amortised cost:
Other receivables (Vendor financing facility) (notes 19(f), 25) 36,276 - - -
Total non-current 36,282 - 6 -
Total other financial assets and liabilities 149,608 26,679 4,711 50,966
((i)) Repayment of $108.8 million was received in the first quarter of 2024 in
accordance with the agreed payment schedule between EnQuest and RockRose
(b) Income statement impact
The income/(expense) recognised for derivatives are as follows:
Year ended 31 December 2023 Revenue and other operating income Cost of
sales
Realised $'000 Unrealised $'000 Realised $'000 Unrealised $'000
Commodity options (21,463) 19,148 - -
Commodity swaps 12,474 9,315 - -
Commodity futures (2,275) - - -
Foreign exchange contracts - - 5,695 -
UKA contracts - - (2,856) (3,832)
(11,264) 28,463 2,839 (3,832)
Year ended 31 December 2022 Revenue and other Cost of
operating income
sales
Realised Unrealised $'000 Realised Unrealised $'000
$'000 $'000
Commodity options (204,943) 20,401 - -
Commodity swaps (86) (5,928) - -
Commodity futures 1,288 2 - -
Foreign exchange contracts - - (5,158) (381)
UKA contracts - - (260) (4,519)
(203,741) 14,475 (5,418) (4,900)
(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 2023, gains totalling $17.2 million (2022:
losses of $189.3 million) were recognised in respect of commodity contracts
designated as FVPL. This included losses totalling $11.3 million (2022: losses
of $203.7 million) realised on contracts that matured during the year, and
mark-to-market unrealised gains totalling $28.5 million (2022: gains of $14.5
million).
The mark-to-market value of the Group's open commodity contracts as at 31
December 2023 was a net liability of $13.9 million (2022: net liability of
$41.8 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 2023, gains totalling
$5.7 million (2022: losses of $5.4 million) were recognised in the Group
income statement. This included realised gains totalling $5.7 million (2022:
losses of $5.2 million) on contracts that matured in the year.
The mark-to-market value of the Group's open contracts as at 31 December 2023
was nil (2022: nil).
(e) UK emissions allowance forward contracts
The Group enters into forward contracts for the purchase of UKAs to manage its
exposure to carbon emission credit prices.
The mark-to-market value of the Group's open contracts as at 31 December 2023
was $8.3 million (2022: $4.4 million).
(f) Other receivables
Other receivables
$'000 Equity shares Total
$'000 $'000
At 1 January 2022 and 2023 - 6 6
Additions((i)) 145,103 - 145,103
At 31 December 2023 145,103 6 145,109
Current 108,827
Non-current 36,282
145,109
((i))Additions relate to a vendor financing facility entered into with
RockRose Energy Limited on 29 December 2023 following the farm-down of a 15.0%
share in the EnQuest Producer FPSO and capital items associated with the
Bressay development. $108.8 million was repaid in the first quarter of 2024
with the remainder of $36.3 million repayable through future net cash flows
from the Bressay field. Interest on the outstanding amount accrues at 2.5%
plus the Bank of England's Base Rate
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
('EBT') 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 shares of £0.05 each Share capital $'000 Share premium Total
Number $'000 $'000
At 1 January 2023 1,885,924,339 131,650 260,546 392,196
Issue of new shares to EBT 26,379,774 1,635 - 1,635
At 31 December 2023 1,912,304,113 133,285 260,546 393,831
At 31 December 2023, there were 8,449,793 shares held by the Employee Benefit
Trust (2022: 21,663,181). The movement in the year was shares used to satisfy
awards made under the Company's share-based incentive schemes offset by a
subscription for additional Ordinary shares.
21. Share-based payment plans
Accounting policy
Eligible employees (including Executive 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 Executive Directors is shown in the Directors'
Remuneration 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:
2023 2022
$'000 $'000
Performance Share Plan 2,120 3,264
Other performance share plans 231 261
Sharesave Plan 969 1,194
3,320 4,719
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 2023 2022
Number Number
Outstanding at 1 January 102,271,264 125,493,995
Granted during the year 33,940,859 17,368,011
Exercised during the year (19,459,260) (15,712,039)
Forfeited during the year (29,385,408) (24,878,703)
Outstanding at 31 December 87,367,455 102,271,264
Exercisable at 31 December 17,944,371 10,490,719
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.
Share options 2023 2022
Number Weighted average exercise price $ Number Weighted average exercise price
$
Outstanding at 1 January 33,308,249 0.14 37,518,927 0.14
Granted during the year 10,268,853 0.14 1,292,788 0.32
Exercised during the year (19,977,354) 0.13 (2,150,313) 0.17
Forfeited during the year (4,941,604) 0.17 (3,353,153) 0.14
Outstanding at 31 December 18,658,144 0.16 33,308,249 0.14
Exercisable at 31 December 6,553,159 0.13 445,318 0.17
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
depicted below is remeasured to fair value at subsequent reporting dates with
changes in fair value recognised in profit or loss. Contingent consideration
that is classified as equity if any, is not remeasured at subsequent reporting
dates and its subsequent settlement is accounted for within equity.
Contingent consideration is discounted at a risk-free rate combined with a
risk premium, calculated in alignment with IFRS 13 and the unwinding of the
discount is presented within finance costs.
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 75% Magnus decommissioning-linked liability Golden Eagle Total
$'000 $'000 $'000 $'000
At 31 December 2022 566,685 21,853 48,337 636,875
Change in fair value (see note 5(d)) (69,840) 175 - (69,665)
Unwinding of discount (see note 6) 56,668 2,186 1,663 60,517
Utilisation (65,506) (4,425) (50,000) (119,931)
At 31 December 2023 488,007 19,789 - 507,796
Classified as:
Current 43,073 3,452 - 46,525
Non-current 444,934 16,337 - 461,271
488,007 19,789 - 507,796
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 profit
share arrangement with bp whereby EnQuest and bp share the net cash flow
generated by the 75% interest on a 50:50 basis, subject to a cap of $1.0
billion received by bp. This contingent consideration is a financial liability
classified as measured at FVPL. 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 2023, which resulted in a
decrease in fair value of $69.8 million (2022: increase of $233.6 million).
The decrease in fair value in 2023 reflects a 1.3% increase in the discount
rate to 11.3% (2022: 10.0%) and changes in the asset cost profile, partially
offset by the Group's increased oil price assumptions. The increase in 2022
reflected the Group's higher long-term oil price assumptions and changes in
asset profiles and cost assumptions. The fair value accounting effect and
finance costs of $56.7 million (2022: $34.5 million) on the contingent
consideration were recognised through remeasurements and exceptional items in
the Group income statement. At 31 December 2023, the contingent profit-sharing
arrangement cap of $1.0 billion was forecast to be met in the present value
calculations (31 December 2022: cap was forecast to be met). Within the
statement of cash flows, the profit share element of the repayment, $65.5
million (2022: $46.0 million) is disclosed separately under investing
activities. At 31 December 2023, the contingent consideration for Magnus was
$488.0 million (31 December 2022: $566.7 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 discount rate, the oil price and the interrelationship
with production and the profit-share arrangement. A 1.0% reduction in the
discount rate applied, which is considered a reasonably possible change given
the prevailing macroeconomic conditions, would increase reported contingent
consideration by $19.9 million. A 1.0% increase would decrease reported
contingent consideration by $18.6 million. As the profit-sharing cap of $1.0
billion is forecast to be met in the present value calculations, sensitivity
analysis has only been undertaken on a reduction in the price assumptions of
10%, which is considered to be a reasonably possible change. This results in a
reduction of $83.3 million to the contingent consideration (2022: reduction of
$73.6 million).
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 2023, the maturity
analysis of the contingent consideration is disclosed in Risk management and
financial instruments: liquidity risk (note 28).
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
2023, the amount due to bp calculated on an after-tax basis by reference to
30% of bp's decommissioning costs on Magnus was $19.8 million (2022: $21.9
million). Any reasonably possible change in assumptions would not have a
material impact on the provision.
Golden Eagle contingent consideration
Part of the Golden Eagle acquisition consideration included an amount that was
contingent on the average oil price between July 2021 and June 2023. Over the
period July 2021 to June 2023, the average oil price was $89.6/bbl. As such,
at 30 June 2023, the contingent consideration was valued at $50.0 million with
settlement of this liability completing in July 2023 (2022: liability of $48.3
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 Total
$'000 $'000 provisions $'000
$'000
At 31 December 2022 691,584 32,720 13,366 737,670
Additions during the year(i) 6,245 - 7,017 13,262
Changes in estimates(i) 78,247 1,605 (5,192) 74,660
Unwinding of discount 24,236 1,145 - 25,381
Utilisation (44,550) (10,160) (797) (55,507)
Foreign exchange - 45 (214) (169)
At 31 December 2023 755,762 25,355 14,180 795,297
Classified as:
Current 55,924 9,757 14,180 79,861
Non-current 699,838 15,598 - 715,436
755,762 25,355 14,180 795,297
(i) Includes $31.2 million relating to assets in decommissioning disclosed in
note 5(e) and $53.3 million related to producing assets disclosed in note 10
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 primarily relate
to the decommissioning provision recognised due to drilling of new wells in
Magnus and Golden Eagle. Changes in estimates during the year primarily
reflect the net effect of $61.0 million increase in the underlying cost
estimates and $35.0 million foreign exchange impact due to the strengthening
Sterling to US Dollar exchange rates. At 31 December 2023, an estimated $175.7
million is expected to be utilised between one and five years (2022: $407.0
million), $355.6 million within six to ten years (2022: $67.6 million), and
the remainder in later periods. For sensitivity analysis see Use of
judgements, estimates and assumptions within note 2.
The Group enters into surety bonds principally to provide security for its
decommissioning obligations. The surety bond facilities, which expired in
December 2022, were renewed for 12 months, subject to ongoing compliance with
the terms of the Group's borrowings. At 31 December 2023, the Group held
surety bonds totalling $250.4 million (2022: $227.6 million).
Thistle decommissioning provision
In 2018, EnQuest exercised 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 the Thistle and Deveron fields, with
the liability recognised within provisions. At 31 December 2023, the amount
due to bp by reference to 7.5% of bp's decommissioning costs on Thistle and
Deveron was $25.4 million (2022: $32.7 million), with the reduction mainly
reflecting the utilisation in the period. Change in estimates of $1.6 million
are included within other expense (2022: $6.1 million other income) and
unwinding of discount of $1.1 million is included within finance income (2022:
$0.8 million).
Other provisions
During 2021, the Group recognised $8.2 million in relation to disputes with
third-party contractors. In 2022, one dispute was settled for $0.5 million and
the other dispute is ongoing. At 31 December 2023, the provision was increased
to $9.1 million (31 December 2022: $7.5 million) reflecting legal costs and
interest charges. The Group expects the dispute to be settled in 2024.
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 (see note 10).
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
the 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 assets Lease liabilities $'000
$'000
As at 31 December 2021 463,393 570,781
Additions in the period 28,394 28,130
Depreciation expense (57,864) -
Impairment charge (2,991) -
Disposal (1,554) (1,432)
Interest expense - 39,172
Payments - (147,971)
Foreign exchange movements - (6,614)
As at 31 December 2022 429,378 482,066
Additions in the period (see note 10) 28,378 28,378
Depreciation expense (see note 10) (55,979) -
Impairment reversal (see note 10) 6,077 -
Disposal (122) -
Interest expense - 43,801
Payments - (135,675)
Foreign exchange movements - 3,604
As at 31 December 2023 407,732 422,174
Current 133,282
Non-current 288,892
422,174
The Group leases assets, including the Kraken FPSO, property, and oil and gas
vessels, with a weighted average lease term of four years. The maturity
analysis of lease liabilities is disclosed in note 28.
Amounts recognised in profit or loss
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000
Depreciation expense of right-of-use assets 55,979 57,864
Interest expense on lease liabilities 43,801 39,172
Rent expense - short-term leases 5,153 7,116
Rent expense - leases of low-value assets 113 50
Total amounts recognised in profit or loss 105,046 104,202
Amounts recognised in statement of cash flows
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000
Total cash outflow for leases 135,675 147,971
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 2023
was $2.3 million (2022: $1.5 million).
The following table sets out a maturity analysis of lease payments, showing
the undiscounted lease payments to be received after the reporting date:
2023 2022
$'000 $'000
Less than one year 2,682 2,313
One to two years 2,011 2,542
Two to three years 872 1,905
Three to four years 873 822
Four to five years 889 824
More than five years 2,790 3,710
Total undiscounted lease payments 10,117 12,116
25. Deferred income
Accounting policy
Income is not recognised in the income statement until it is highly probable
that the conditions attached to the income will be met.
Year ended 31 December 2023 Year ended 31 December 2022
$'000 $'000
Deferred income 138,416 -
In December 2023 a farm-down of an equity interest in the EnQuest Producer
FPSO and certain capital spares related to the Bressay development was
completed and cash received of $141.3 million. The same amount was lent back
to the acquirer in December 2023 as vendor financing (see note 19(f)).
Proceeds from the transaction are reported within deferred income, as these
are contingent upon the Bressay development project achieving regulatory
approval. Both parties are committed to delivering the development, however
should the project not achieve regulatory approval there remains the option to
deploy the assets on an alternative project.
26. Commitments and contingencies
Capital commitments
At 31 December 2023, the Group had commitments for future capital expenditure
amounting to $43.8 million (2022: $9.5 million). The key components of this
relate to drilling commitments for the Kraken and Golden Eagle fields and
commitments for the new stabilisation facility at Sullom Voe Terminal. Where
the commitment relates to a joint venture, the amount represents the Group's
net share of the commitment. Where the Group is not the operator of the joint
venture then the amounts are based on the Group's net share of committed
future work programmes.
Other commitments
In the normal course of business, the Group will obtain surety bonds, Letters
of Credit and guarantees. At 31 December 2023, the Group held surety bonds
totalling $250.4 million (2022: $227.6 million) to provide security for its
decommissioning obligations. See note 23 for further details.
Contingencies
The Group becomes involved from time to time in various claims and lawsuits
arising in the ordinary course of its business. Outside of those already
provided, 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.
A contingent payment of $15.0 million to Equinor is due upon regulatory
approval of a Bressay field development plan.
27. 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 29 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 2023 (2022: none).
Within the $150.0 million Term Loan, Double A Limited, a company beneficially
owned by the extended family of Amjad Bseisu, lent $9.0 million on the same
terms and conditions as all other lending parties. This is considered a
smaller related party transaction under Listing Rule 11.1.10.
Compensation of key management personnel
The following table details remuneration of key management personnel of the
Group. Key management personnel comprise Executive and Non-Executive Directors
of the Company and the Executive Committee.
2023 2022
$'000 $'000
Short-term employee benefits 5,360 6,195
Share-based payments 144 3,049
Post-employment pension benefits 241 164
Termination payments 367 228
6,112 9,636
28. 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.
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 2023 and 2022, 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 facility, the Group is required to
hedge a minimum of 45% of volumes of net entitlement production expected to be
produced in the next 12 months, and between 35% and 15% of volumes of net
entitlement production expected for the following 12 months dependent on the
proportion of the facility that is utilised. 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 2023 are disclosed in note 19. As of 31 December 2023, the Group
held financial instruments (options and swaps) related to crude oil that
covered 5.2 MMbbls of 2024 production and 1.6 MMbbls of 2025 production. The
instruments have an effective average floor price of around $60/bbl in both
2024 and 2025. 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 2023.
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 increase -$10/bbl decrease $'000
$'000
31 December 2023 (4,000) 7,400
31 December 2022 (25,321) 19,922
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 9.00% 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 22%
(2022: 26%) of the Group's sales and 95% (2022: 85%) 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 2023 GBP MYR Other Total
$'000 $'000 $'000 $'000
Total financial assets 241,844 42,233 954 285,031
Total financial liabilities 618,235 9,801 1,295 629,331
Year ended 31 December 2022 GBP MYR Other Total
$'000 $'000 $'000 $'000
Total financial assets 45,732 38,664 746 85,142
Total financial liabilities 502,307 13,202 151 515,660
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 increase 10% rate decrease $'000
$'000
31 December 2023 (34,908) 34,908
31 December 2022 (50,615) 50,615
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 2023, there were no trade receivables past due
but not impaired (2022: nil) and no joint venture receivables past due (2022:
$0.1 million) but not impaired. Receivable balances are monitored on an
ongoing basis with appropriate follow-up action taken where necessary. Any
impact from ECL is disclosed in note 16.
Ageing of past due but not impaired receivables 2023 2022
$'000 $'000
Less than 30 days - -
30-60 days - -
60-90 days - -
90-120 days - -
120+ days - 123
- 123
At 31 December 2023, the Group had one customer accounting for 58% of
outstanding trade receivables (2022: two customers, 79%) and no joint venture
partner accounting for over 10% of outstanding joint venture receivables
(2022: one joint venture partner, 25%).
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 2023,
$166.2 million (2022: $47.3 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 contingent consideration is disclosed below. All of the Group's
liabilities, except for the RBL and Term Loan facilities, are unsecured.
Year ended 31 December 2023 On demand $'000 Up to 1 year $'000 1 to 2 years $'000 2 to 5 years $'000 Over 5 years $'000 Total
$'000
Loans and borrowings - 64,518 131,081 221,311 - 416,910
Bonds - 50,749 50,749 576,415 - 677,913
Contingent consideration - 46,555 95,335 289,823 393,187 824,900
Obligations under finance leases - 160,341 70,062 229,310 36,322 496,035
Trade and other payables - 347,408 13,167 19,750 - 380,325
- 669,571 360,394 1,336,609 429,509 2,796,083
Year ended 31 December 2022 On demand $'000 Up to 1 year $'000 1 to 2 years $'000 2 to 5 years $'000 Over 5 Total
years $'000 $'000
Loans and borrowings - 163,223 175,400 152,000 - 490,623
Bonds - 194,991 49,919 615,449 - 860,359
Contingent consideration - 126,910 85,267 327,642 400,480 940,299
Obligations under finance leases - 151,621 127,592 256,139 37,693 573,045
Trade and other payables - 426,643 - - - 426,643
- 1,063,388 438,178 1,351,230 438,173 3,290,969
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 2023 On demand $'000 Less than 3 months 3 to 12 months 1 to 2 years $'000 Over 2 years $'000 Total
$'000 $'000 $'000
Commodity derivative contracts 414 3,111 17,264 1,000 - 21,789
Other derivative contracts - 8,261 - - - 8,261
414 11,372 17,264 1,000 - 30,050
Year ended 31 December 2022 On demand $'000 Less than 3 months 3 to 12 1 to 2 years $'000 Over 2 years $'000 Total
$'000 Months $'000
$'000
Commodity derivative contracts 9,549 27,496 15,553 - - 52,598
Other derivative contracts 880 4,429 - - - 5,309
10,429 31,925 15,553 - - 57,907
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 shareholder distributions are
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
11 to 15).
2023 2022
$'000 $'000
Loans, borrowings and bond(i) (A) (see note 18) 794,453 1,018,712
Cash and short-term deposits (see note 14) (313,572) (301,611)
EnQuest net debt (B) (ii) 480,881 717,101
Equity attributable to EnQuest PLC shareholders (C) 456,728 484,241
Profit/(loss) for the year attributable to EnQuest PLC shareholders (D) (30,833) (41,234)
Profit/(loss) for the year attributable to EnQuest PLC shareholders excluding 29,213 212,346
remeasurements and exceptionals (E)
Adjusted EBITDA (F) (ii) 824,666 979,084
Gross gearing ratio (A/C) 1.7 2.1
Net gearing ratio (B/C) 1.1 1.5
EnQuest net debt/adjusted EBITDA (B/F) (ii) 0.6 0.7
Shareholders' return on investment (D/C) N/A N/A
Shareholders' return on investment excluding exceptionals (E/C) 6% 44%
(i) Principal amounts drawn, excludes netting off of fees (see note 18)
(ii) See Glossary - non GAAP Measures on pages 65 to 68
29. Subsidiaries
At 31 December 2023, EnQuest PLC had investments in the following
subsidiaries:
Name of company Principal activity Country of incorporation Proportion of nominal value of issued ordinary 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%
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) Leasing 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) Limited1 Construction, ownership and operation of an oil pipeline Scotland 100%
EnQuest Global Services Limited(i)2 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)3
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%
Veri Energy (CCS) Limited(i) Assessment and development of new energy and decarbonisation opportunities England 100%
Veri Energy (Hydrogen) Limited((i)) Assessment and development of new energy and decarbonisation opportunities England 100%
Veri Energy Holdings Limited Intermediate holding company England 100%
Veri Energy Limited(i) Assessment and development of new energy and decarbonisation opportunities 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 Annan House, Palmerston Road, Aberdeen, Scotland, AB11 5QP, United
Kingdom
2 Ground Floor, Colomberie House, St Helier, JE4 0RX,(,) Jersey
3 c/o TMF, 10th Floor, Menara Hap Seng, No. 1 & 3, Jalan P. Ramlee
50250 Kuala Lumpur, Malaysia
30. Cash flow information
Cash generated from operations
Notes Year ended 31 December 2023 Year ended
31 December 2022
$'000
$'000
Profit/(loss) before tax 231,779 203,214
Depreciation 5(c) 6,109 6,222
Depletion 5(b) 292,199 327,026
Exploration and appraisal expense 5,640 -
Net impairment charge to oil and gas assets 4 117,396 81,049
Net (write back)/disposal of inventory (622) 762
Share-based payment charge 5(f) 3,320 4,719
Change in Magnus related contingent consideration 22 (10,811) 268,910
Change in provisions 23 59,970 (25,001)
Other non-cash income 5(d) (4,058) (6,636)
Change in Golden Eagle related contingent consideration 22 1,663 3,162
Option premium recognition - 1,331
Unrealised (gain)/loss on commodity financial instruments 5(a) (28,463) (14,475)
Unrealised loss/(gain) on other financial instruments 5(b) 3,832 4,900
Unrealised exchange loss/(gain) 12,401 (13,588)
Net finance expense 140,213 154,492
Operating cashflow before working capital changes 830,568 996,087
Decrease in trade and other receivables 51,724 12,714
Increase in inventories (9,518) (5,388)
(Decrease)/increase in trade and other payables (18,028) 22,736
Cash generated from operations 854,746 1,026,149
Changes in liabilities arising from financing activities
Loans and borrowings $'000 Bonds Lease liabilities $'000 Total
$'000 $'000
At 1 January 2022 (402,065) (1,109,920) (570,781) (2,082,766)
Cash movements:
Repayments of loans and borrowings 415,000 827,166 - 1,242,166
Proceeds from loans and borrowings (409,180) (376,163) - (785,343)
Payment of lease liabilities - - 147,971 147,971
Cash interest paid in year 14,771 80,189 - 94,960
Non-cash movements:
Additions 4,038 14,323 (28,130) (9,769)
Interest/finance charge payable (14,490) (62,262) (39,172) (115,924)
Fee amortisation (22,679) (2,652) - (25,331)
Disposal - - 1,432 1,432
Foreign exchange and other non-cash movements 1,077 32,036 6,614 39,727
At 31 December 2022 (413,528) (597,283) (482,066) (1,492,877)
Cash movements:
Repayments of loans and borrowings 265,809 138,052 - 403,861
Proceeds from loans and borrowings (166,782) - - (166,782)
Payment of lease liabilities - - 135,675 135,675
Cash interest paid in year 36,285 62,130 - 98,415
Non-cash movements:
Additions - - (28,377) (28,377)
Interest/finance charge payable (30,708) (58,999) (43,801) (133,508)
Fee amortisation (1,476) (3,091) - (4,567)
Foreign exchange and other non-cash movements (810) (11,828) (3,605) (16,243)
At 31 December 2023 (311,210) (471,019) (422,174) (1,204,403)
Reconciliation of carrying value
Loans and borrowings (see Bonds Lease liabilities (see Total
note 18) (see note 24) $'000
$'000 note 18) $'000
$'000
Principal (417,967) (600,745) (482,066) (1,500,778)
Unamortised fees 4,609 13,815 - 18,424
Accrued interest (note 17) (170) (10,353) - (10,523)
At 31 December 2022 (413,528) (597,283) (482,066) (1,492,877)
Principal (319,784) (474,669) (422,174) (1,216,627)
Unamortised fees 8,553 10,724 - 19,277
Accrued interest (note 17) 21 (7,074) - (7,053)
At 31 December 2023 (311,210) (471,019) (422,174) (1,204,403)
31. Subsequent events
In March 2024, the UK Government announced that the sunset clause for EPL
would be extended by a year to 31 March 2029, although no date has yet been
set for when this will be legislated. The Group estimates the impact of this
one year extension to be an additional deferred tax liability of approximately
$44.6 million, with a reduction in the carrying value of the Group's assets of
approximately $22.3 million.
In February 2024, the regulator approved the 15.0% disposal of a share in the
Bressay licence to RockRose.
By the end of February 2024, the Group had fully repaid the outstanding $140.0
million of its drawn Reserve Based Lending Facility.
The Board of Directors of EnQuest PLC are proposing making a $15.0 million
share buy back, to be executed during 2024. The distribution will be below
the limit granted at the 2023 Annual General Meeting allowing the Company to
purchase up to 10% of its issued Ordinary share capital in the market.
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 but consistent with accounting
policies applied in the financial statements. 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 33.
Business performance net profit attributable to EnQuest PLC 2023 2022
shareholders
$'000 $'000
Reported net profit/(loss) (A) (30,833) (41,234)
Adjustments - remeasurements and exceptional items (note 4):
Unrealised gains on derivative contracts (note 19) 24,631 9,575
Net impairment (charge)/reversal to oil and gas assets (note 10, note 11 and (117,396) (81,049)
note 12)
Finance costs on Magnus contingent consideration (note 6) (58,854) (36,410)
Change in Magnus contingent consideration (2023: notes 5(d); 2022: notes 5(d) 69,665 (232,500)
and 5(e))
Movement in other provisions 3,374 -
Other exceptional income (note 5(d)) 4,127 6,636
Other exceptional expenses (note 5(e)) (10,731) -
Other exceptional finance income (note 6) - 2,148
Pre-tax remeasurements and exceptional items (B) (85,184) (331,600)
Tax on remeasurements and exceptional items (C) 25,138 78,020
Post-tax remeasurements and exceptional items (D = B + C) (60,046) (253,580)
Business performance net profit attributable to EnQuest PLC shareholders (A - 29,213 212,346
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 reserve
based lending ('RBL') facility and term loan. 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/(loss)
before tax and finance income/(costs).
Adjusted EBITDA 2023 2022
$'000 $'000
Reported profit from operations before tax and finance income/(costs) 456,227 411,887
Adjustments:
Remeasurements and exceptional items (note 4) 26,330 297,338
Depletion and depreciation (note 5(b) and note 5(c)) 298,308 333,248
Inventory revaluation (622) 763
Change in provision (note 5(d) and note 5(e)) 32,764 (42,823)
Net foreign exchange loss/(gain) (note 5(d) and 5(e)) 11,659 (21,329)
Adjusted EBITDA (E) 824,666 979,084
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 15 to 16.
Total cash and available facilities 2023 2022
$'000 $'000
Available cash 313,028 293,866
Restricted cash 544 7,745
Total cash and cash equivalents (F) (note 14) 313,572 301,611
Available credit facilities 518,794 505,692
Credit facility - drawn down (290,000) (405,692)
Letter of credit (note 18) (43,545) (52,700)
Available undrawn facility (G) 185,249 47,300
Total cash and available facilities (F + G) ((i)) 498,821 348,911
(i) Includes $19.0 million in relation to a vendor loan facility which expired
on 1 January 2024. This facility is currently being renegotiated.
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 deleveraging 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 15 to 16. The
Group's definition of net debt, referred to as EnQuest net debt, excludes the
Group's finance lease liabilities as the Group's focus is the management of
cash borrowings and a lease is viewed as deferred capital investment.
EnQuest net debt 2023 2022
$'000 $'000
Borrowings (note 18):
RBL facility 135,080 395,391
Term Loan facility 146,367 -
SVT working capital facility 29,784 12,275
Vendor loan facility - 5,692
Borrowings (H) 311,231 413,358
Bonds (note 18):
High yield bond 294,276 291,185
Retail bonds 169,669 295,745
Bonds (I) 463,945 586,930
Non-cash accounting adjustments (note 18):
Unamortised fees on loans and borrowings 8,553 4,609
Unamortised fees on bonds 10,724 13,815
Non-cash accounting adjustments (J) 19,277 18,424
Debt (H + I + J) (K) 794,453 1,018,712
Less: Cash and cash equivalents (note 14) (E) 313,572 301,611
EnQuest net debt (K - F) (L) 480,881 717,101
The EnQuest net debt/adjusted EBITDA metric is a ratio that provides
management and users of the Group's consolidated financial statements with an
indication of the Group's ability to settle its debt. This is a helpful metric
to monitor the Group's progress against its strategic objective of
deleveraging.
EnQuest net debt/adjusted EBITDA 2023 2022
$'000 $'000
EnQuest net debt (L) 480,881 717,101
Adjusted EBITDA (E) 824,666 979,084
EnQuest net debt/adjusted EBITDA (L/E) 0.6 0.7
Cash capital expenditure (nearest equivalent measure on an IFRS basis is
purchase of property, plant and equipment) monitors investing activities on a
cash basis, while cash decommissioning expense monitors the Group's cash spend
on decommissioning activities. The Group provides guidance to the financial
markets for both these metrics given the materiality of the work programme and
the focus on the Group's liquidity position and ability to reduce its debt.
Cash capital and decommissioning expense 2023 2022
$'000 $'000
Reported net cash flows from/(used in) investing activities (206,895) (161,247)
Adjustments:
Purchase of other intangible assets 876 1,199
Payment of Magnus contingent consideration - Profit share 65,506 45,975
Payment of Golden Eagle contingent consideration - Acquisition costs 50,000 -
Proceeds received from farm-down of equity interest in the EnQuest Producer (55,800) -
FPSO
Interest received (5,895) (1,763)
Cash capital expenditure (152,208) (115,836)
Decommissioning expenditure (58,911) (58,964)
Cash capital and decommissioning expense (211,119) (174,800)
Free cash flow ('FCF') represents the cash a company generates, after
accounting for cash outflows to support operations and to maintain its capital
assets. Currently this metric is useful to management and users to assess the
Group's ability to reduce its debt.
The Group's definition of free cash flow is net cash flow adjusted for net
repayment/proceeds of loans and borrowings, net proceeds of share issues and
cost of acquisitions.
Free cash flow 2023 2022
$'000 $'000
Net cash flows from/(used in) operating activities 754,244 931,553
Net cash flows (used in)/from investing activities (262,695) (161,247)
Net cash flows (used in)/from financing activities (478,631) (731,163)
Adjustments:
Proceeds from loans and borrowings((i)) (190,657) (87,215)
Repayment of loans and borrowings((i)) 427,736 567,020
Payment of Golden Eagle contingent consideration - Acquisition costs 50,000 -
Free cash flow 299,997 518,948
(i) For the prior year, $21.7 million
has been reclassed between proceeds from loans and borrowings and repayments
of loans and borrowings to better represent the substance of the transaction
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.
Revenue sales 2023 2022
$'000 $'000
Revenue from crude oil sales (note 5(a)) (M) 1,127,419 1,517,666
Revenue from gas and condensate sales (note 5(a)) (N) 338,973 514,206
Realised (losses)/gains on oil derivative contracts (note 5(a)) (P) (11,264) (203,741)
Barrels equivalent sales 2023 2022
kboe kboe
Sales of crude oil (Q) 13,714 14,786
Sales of gas and condensate(i) 4,107 3,366
Total sales (R) 17,821 18,152
(i) Includes volumes related to onward sale of third-party gas purchases not
required for injection activities at Magnus
Average realised prices 2023 2022
$/Boe $/Boe
Average realised oil price, excluding hedging (M/Q) 82.2 102.6
Average realised oil price, including hedging ((M + P)/Q) 81.4 88.9
Operating costs ('opex') is a measure of the Group's cost management
performance (reconciled to reported cost of sales, the nearest equivalent
measure on an IFRS basis). 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 2023 2022
$'000 $'000
Reported cost of sales (note 5(b)) 946,752 1,200,706
Adjustments:
Remeasurements and exceptional items (note 5(b)) (5,650) (4,900)
Depletion of oil and gas assets (note 5(b)) (292,199) (327,027)
Credit/(charge) relating to the Group's lifting position and inventory (note 4,244 15,568
5(b))
Other cost of operations((i)) (note 5(b)) (305,919) (487,831)
Operating costs 347,228 396,516
Less: realised loss/(gain) on derivative contracts (S) (note 5(b)) 2,839 (5,418)
Operating costs directly attributable to production 350,067 391,098
Comprising of:
Production costs (T) (note 5(b)) 308,331 347,832
Tariff and transportation expenses (U) (note 5(b)) 41,736 43,266
Operating costs directly attributable to production 350,067 391,098
(i) Includes $294.0 million (2022: $452.8 million) of purchases and associated
costs of third-party gas not required for injection activities at Magnus which
is sold on
Barrels equivalent produced 2023 2022
kboe kboe
Total produced (working interest) (V)((i)) 15,992 17,250
(i) Production for 2023 includes 604 kboe associated with Seligi gas
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 its risk to market
price movements.
Unit opex 2023 2022
$/Boe $/Boe
Production costs (T/V) 19.3 20.2
Tariff and transportation expenses (U/V) 2.6 2.5
Total unit opex ((T + U)/V) 21.9 22.7
Realised (gain)/loss on derivative contracts (S/V) (0.2) 0.3
Total unit opex including hedging ((S + T+ U)/V) 21.7 23.0
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