REG - EnQuest PLC - Results for the year ended 31 December 2024
27/03/2025 07:15
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RNS Number : 4663C EnQuest PLC 27 March 2025
EnQuest PLC, 27 March 2025
Results for the year ended 31 December 2024 and 2025 outlook
Delivering operational excellence and diversified growth
Unless otherwise stated, all figures are in US Dollars.
Comparative figures for the Income Statement relate to the year ended 31
December 2023 and the Balance Sheet as at 31 December 2023.
Alternative performance measures are reconciled within the 'Glossary -
Non-GAAP measures' at the end of the Financial Statements.
EnQuest Chief Executive, Amjad Bseisu, said:
"The Group delivered another outstanding year of operational performance in
2024, with production efficiency at 90% across the asset portfolio,
representing a continuation of the excellence that defines our status as a
top-quartile operator and expert in late-life asset management. After
producing 40.7 Kboed in 2024, year-to-date production from our existing
portfolio, as of the end of February 2025, was 43.0 Kboed (excluding Vietnam),
tracking ahead of our guidance range of 40-45 Kboed, which includes
approximately 5 Kboed of pro forma volumes for Vietnam. Demonstrating our
differentiated operational capability across the transition lifecycle, we have
continued to consolidate our position as a leading exponent of decommissioning
activities, having been responsible for more than 35% of the wells plugged and
abandoned in the North Sea over the past three years.
"In recent months, the Group has executed successive material growth
transactions across South East Asia, providing geographic and commodity
diversification within the portfolio. Our entry into Vietnam, through the
Block 12W acquisition, and our increased presence in Malaysia, with the
enhancement of our Seligi gas agreement and the DEWA gas development PSC
award, are all underpinned by leveraging our differentiated operating
capability to create asset value. As EnQuest continues to pursue growth in the
UK North Sea and further potential new country entries in South East Asia,
these transactions underscore our commitment to growth, a disciplined approach
to M&A, and a strategy to invest capital where we identify the most
favourable returns.
"Our foundation for growth is robust and we are well-positioned to transact,
with our transaction ready liquidity increasing to c.$550 million at the end
of February, following the latest redetermination of the Group's reserve-based
lending ('RBL') facility, which remains fully undrawn. Having consistently
delivered against production, operational and cost targets, we have generated
material free cash flows across recent years, even during periods of reduced
commodity prices. This commitment to delivery, against the backdrop of a
challenging fiscal environment in the UK, has seen us reduce EnQuest net debt
by more than $1.6 billion since its peak.
"Reflecting the strength of our core business and the Group's commitment to
sustainable shareholder returns, I am pleased that the Board has proposed a
final 2024 dividend of $15 million, subject to shareholder approval."
2024 performance
§ EnQuest continued to deliver top quartile performance across its asset
portfolio, which is 96% operated by the Group.
§ Group operated production efficiency c.90%, delivering average production
of 40,736 Boepd (2023: 43,812 Boepd).
§ 2P reserves 168.6 MMboe (2023: 174.9 MMboe), 14.0 MMboe of production
almost fully replaced by South East Asian growth.
§ Investment in fast payback projects to diversify production, manage natural
field decline, lower costs and reduce emissions.
§ $95.1 million reduction in EnQuest net debt, to $385.8 million (31 December
2023: $480.9 million).
§ Revenue and other income $1,180.7 million (2023: $1,487.4 million);
adjusted EBITDA $672.6 million (2023: $824.7 million); reported profit after
tax $93.8 million (2023: $30.8 million loss).
§ Capital investment $252.9 million (2023: $152.2 million), inclusive of
$65.9 million Magnus Flare Recovery project. Decommissioning expenditure $60.5
million (2023: $58.9 million), focused on well plug and abandonment campaigns.
§ Maiden shareholder distribution in 2024, $9 million share buyback
completed.
2025 outlook
§ 2025 is a pivotal year, with EnQuest focused on delivering a
transformational UK deal and accelerating its growth in South East Asia.
§ In the UK North Sea 2024 saw transactional activity fall, but with fiscal
clarity provided by the UK Autumn Budget statement, the Group continues to
progress several UK transaction processes.
§ In South East Asia, EnQuest has recently delivered the acquisition of
Harbour Energy's Vietnam business (7.5 MMboe net 2P reserves, c.5.3 Kboed of
pro forma 2025 production); secured the Seligi 1b gas sales agreement (13
MMboe net 2P reserves, c.6.0 Kboed from mid-2026); and been awarded the DEWA
PSC (c.500 Bscf of gas in place, c.18 Kboed production potential).
§ A 34% expansion in the Group's RBL capacity at year-end redetermination has
boosted EnQuest's transactional liquidity (cash and available facilities) at
28 February 2025 to $549.0 million (31 December 2024: $474.5 million).
§ EnQuest is pleased to propose a 2024 final dividend of 0.616 pence per
share, equivalent to c.$15 million, payable in June 2025 following shareholder
approval at the Group's Annual General Meeting.
§ Net Group production is expected to average between 40,000 and 45,000 Boepd
(pro forma basis, including Vietnam volumes).
§ Production from the current portfolio, excluding Vietnam, averaged 43,037
Boepd to the end of February 2025.
§ Operating expenditure expected to total c.$450 million; capital investment
expected to total c.$190 million; Decommissioning expenditure expected to
total c.$60 million, all on a pro forma basis.
§ Kraken FPSO lease rate reduces by c.70% from 1 April 2025.
Production and financial information
Macro conditions 2024 2023 Change
Brent oil price(4) ($/bbl) 80.5 82.5 -2.4%
Natural gas price(5) (GBp/Therm) 83.6 98.9 -15.5%
Alternative performance measures ('APMs') 2024 2023 Change
Production (Boepd) 40,736 43,812 -7.0%
Realised oil price ($/bbl)(1,2) 80.2 81.4 -1.5%
Average unit operating costs ($/Boe)(2) 25.3 21.9 15.5%
Adjusted EBITDA ($m)(2) 672.6 824.7 -18.4%
Cash expenditures ($m) 313.4 211.1 48.5%
Capital(2) 252.9 152.2 66.2%
Decommissioning 60.5 58.9 2.7%
Adjusted free cash flow ($m)(2) 53.2 300.0 -82.3%
End 2024 End 2023
EnQuest net (debt)/cash ($m)(2) (385.8) (480.9) -19.8%
Statutory measures 2024 2023 Change
%
Reported revenue and other operating income ($m)(3) 1,180.7 1,487.4 -20.6%
Cost of sales ($m) (787.4) (946.8) -16.8%
Reported gross profit ($m) 393.3 540.7 -27.3%
Reported profit/(loss) after tax ($m) 93.8 (30.8) n/a
Reported basic earnings/(loss) per share (cents) 5.0 (1.6) n/a
Net cash flow from operating activities ($m) 508.8 754.2 -32.5%
Net increase/(decrease) in cash and cash equivalents ($m) (27.7) 12.9 n/a
Notes:
(1) Including realised losses of $12.9 million (2023: realised losses of $11.3
million) associated with EnQuest's oil price hedges
(2) See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP Measures' starting on page 70.
(3) Including net realised and unrealised losses of $9.8 million (2023: net
realised and unrealised gains of $17.2 million) associated with EnQuest's oil
price hedges
(4) Source is Reuters Factset
(5) Source is ICIS Heren NBP day-ahead
- 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 and Corporate Affairs)
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 10:00 today - London
time. The presentation will be accessible via a webcast by clicking here
(https://url.uk.m.mimecastprotect.com/s/8Ed1CvQVpFAnJQ4SXhvUQ87Zx?domain=google.com)
.
The EnQuest team will be hosting a presentation via Investor Meet Company,
primarily focused on the Company's retail investors on 24 April at 10:00 -
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:
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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 Kate Christ,
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
EnQuest is an expert in managing assets in mature basins. We do this by
improving operational uptime, lowering costs and extending asset life. At the
end of an asset's economic life, we either safely decommission it or repurpose
it for a low carbon future.
Across the UK North Sea and South East Asia, we operate c.96% of our 2P
reserves. This means we have strong control over how we deploy our people and
capital. Our focus is to invest in maintenance and low-cost, fast-payback
opportunities that diversify production, help manage natural field declines,
lower costs and reduce emissions. We have been careful to enter these assets
with financial agreements that minimise our exposure to decommissioning costs.
Delivering diversified growth is central to our strategy. In the UK North Sea,
we remain focused on utilising our core operational skills and advantaged tax
position to deliver a deal that propels us into the top tier of producers.
This will expand the Group's cash flow, enabling us to boost shareholder
distributions and accelerate our growth in South East Asia.
Since ending 2024, we have grown our cash and available facilities to $549.0
million as at 28 February 2025. This provides a strong foundation from which
to transact, and we are focused on 2025 as a year of transformational
delivery.
Market conditions
In 2024, wars in Ukraine and Gaza intensified and over 70 countries,
representing more than half of the world's population, held national
elections. Despite this complex geopolitical mix, oil prices were lower but
relatively stable, with Brent averaging $80.5/bbl.
In the UK, the Labour Party entered power following the General Election with
a strong majority and a manifesto pledge to tighten fiscal conditions in the
UK North Sea, despite the UK being the only country in the world to maintain a
windfall tax on oil and gas producers in 2024. The new government used its
first Budget Statement to increase the Energy Profits Levy ('EPL') rate to 38%
and extended its duration to 31 March 2030. This was the fifth material
amendment to UK sector taxation in the last two and a half years. Such
volatility undermines North Sea investment and impacts jobs and equipment that
are essential to delivering the UK's transition ambitions.
As more industry participants accelerate their shift in focus away from the UK
North Sea, we retain the view that a significant proportion of UK production
is transactable, and we are clear in our desire to be a sector consolidator.
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.
The combination of this relative tax advantage and our differentiated
operating capability, including demonstrable decommissioning expertise, make
EnQuest the right operator to maximise the value of mature assets in the North
Sea.
EnQuest has a track record of demonstrating resilience, creativity, and
adaptability, and can generate opportunities in such circumstances. Having
consistently delivered against production, operational and cost targets, we
have generated material-free cash flows across recent years, even during
periods of significantly reduced commodity prices.
This commitment to delivery, against the backdrop of a challenging UK fiscal
environment, has seen us reduce EnQuest net debt by more than $1.6 billion
since its peak. With no outstanding debt maturities until 2027, now is the
time for EnQuest to build on that strong foundation as we look to deliver
material growth in the UK and accelerate the value of our significant UK tax
asset.
Exceptional operating performance
In 2024, EnQuest delivered production efficiency of c.90% across its operated
portfolio, production averaging 40,736 Boepd (2023: 43,812 Boepd). 80% of this
production originated from the UK North Sea and 88% of Group output was oil.
With 88% production efficiency, our North Sea assets again significantly
exceeded the industry's average basin performance (c.77%). Given EnQuest's
focus on late-life assets, this is a standout achievement.
The Kraken field continued to perform at the very top of the production
efficiency for floating hubs, the FPSO's 95.5% production efficiency exceeding
North Sea average efficiency by c.25%.
High levels of uptime at Magnus were offset by minor delays to the five-yearly
rig recertification, which in turn delayed the start-up of several new wells.
The field also suffered an outage on third-party infrastructure in the fourth
quarter of 2024. To mitigate this, the Group designed and executed a well
optimisation campaign that added over 1,000 Boepd of incremental production.
Production efficiency in Malaysia averaged 94% and production totalled 8,149
Boepd (10% up on 2023). This was underpinned by three new infill wells and
strong domestic demand for associated Seligi 1a gas, for which EnQuest
receives a handling and delivery fee.
EnQuest is successfully delivering against a key component of its strategy by
delivering diversified growth, with successive South East Asian transactions,
that provide geographic and commodity diversification within the portfolio.
Our entry into Vietnam through the Block 12W acquisition and extending our
Malaysian footprint with the expansion of our Seligi gas agreement and the
DEWA PSC award are all underpinned by EnQuest's differentiated operating
capability and our ability to deploy our expertise to create asset value. As
EnQuest continues to work towards a transaction in the UK North Sea and
further potential new country entries in South East Asia, these agreements
underline our commitment to growth, a disciplined approach to M&A, and a
strategy to deploy capital where we see the most favourable returns.
At the other end of the lifecycle of our asset portfolio, EnQuest plugged and
abandoned ('P&A') another 22 wells, and the Group remains on track to
complete well P&A work on both Heather and Thistle in 2025. Although we
have delivered more than 35% of the total well P&A work in the North Sea
over the last three years, our exposure to the cost of this work remains one
of the lowest in the basin, as these costs have mostly been left behind with
the original owners of the assets. We continue to deliver P&A activities
at a per well cost that is significantly below the North Sea Transition
Authority ('NSTA') industry benchmark, and in recognition of our
decommissioning expertise, in 2024 Shell transferred to EnQuest its
decommissioning management role of the Greater Kittiwake Area.
Having produced c.14 MMboe of hydrocarbons in 2024, we almost fully replaced
these volumes through 2P reserve additions in South East Asia, with Group 2P
reserves totalling 168.6 MMboe at 31 December 2024 (2023: 174.9 MMboe). 2C
resources also remained robust, totalling c.354 MMboe, Bressay and Bentley
each holding more than 100 MMboe of net resource.
Post the period end, EnQuest added a further 7.5 MMboe of 2P and reserves and
4.9 MMboe of 2C resource through the acquisition of Harbour's Vietnam
operations.
Financial performance
The Group's continued solid financial and operating performance in the period
drove further strengthening of EnQuest's balance sheet and enabled the focus
of the business to pivot to shareholder distributions and growth.
We reduced our EnQuest net debt by a further $95.1 million, to $385.8 million
(31 December 2023: $480.9 million) and we were delighted to execute our first
shareholder return programme, repurchasing $9.0 million of capital via a share
buyback.
Lower commodity prices, production and the Magnus crossover gas component
reduced Group revenue to $1,180.7 million (2023: $1,487.4 million). The Magnus
crossover gas also drove a reduction in cost of sales, with production costs
flat year-on-year. Production costs were, however, flat year-on-year at
$20.6/boe. Adjusted EBITDA fell by 18.5%, to $672.6 million (2023: $824.7
million) but EnQuest's effective tax rate fell to 43.7% (2023: 113.3%) due to
the recognition of additional carried forward tax losses. As a result, the
Group reported a post-tax profit of $93.8 million (2023: $30.8 million loss).
Capital expenditure in the period rose to $252.9 million, primarily relating
to the Magnus five-yearly rig recertification, Golden Eagle drilling,
decarbonisation projects at SVT, and the emission-reducing Magnus Flare Gas
Recovery project (2023: $152.2 million). Decommissioning expenditure totaled
$60.5 million (2023: $58.9 million). In the period, we also received repayment
of a vendor loan that was provided to RockRose as part of the 2023 Bressay
farm-down.
We used our financial strength to make $130.6 million of net repayments on our
loans and borrowings (2023: $237.1 million), repaying our RBL facility in full
($140.0 million) in Q1 2024 and, in Q4 2024, repaying the entire $150.0
million term loan facility through a $160.0 million tap of EnQuest's high
yield bond, which has simplified transaction-ready access to our RBL.
Following the RBL redetermination process at the end of 2024 and with no
further drawdowns in the first quarter of 2025, $237.1 million of the RBL
facility remains available to EnQuest for future drawdown.
We understand the importance of distributions to our shareholders and, having
ended 2024 with a strong financial position, EnQuest is pleased to propose its
maiden dividend, which for 2025 will be 0.616 pence per share, equivalent to
c.$15 million.
Environmental, Social and Governance
Against the 2018 baseline established by the NSTA's North Sea Transition Deal,
we have reduced our absolute UK Scope 1 and Scope 2 emissions by over 40%,
providing a strong foundation for our commitment to reach net zero in Scope 1
and Scope 2 emissions by 2040.
Work continues to decarbonise existing portfolio infrastructure. Examples of
these initiatives include the Magnus Flare Gas Recovery project, which was
sanctioned in 2024, and development of the Bressay gas cap, for which we
target regulatory approval later this year. At the Sullom Voe Terminal ('SVT')
on Shetland, we are progressing two significant projects: the New
Stabilisation Facility ('NSF') and the long-term power solution, which
together will reduce SVT's carbon footprint by c.90%.
Under the management of Veri Energy, a wholly owned subsidiary of EnQuest, we
are also supporting the UK's transition ambitions by progressing several
scalable renewable energy and decarbonisation projects.
The health, safety and wellbeing of our employees remains our top priority. In
2024, our Lost Time Incident ('LTI') performance fell short of our
expectations and was out of line with the Group's recent safety record.
EnQuest aims to be in the upper quartile for safety performance and is working
closely with all contractors to ensure that everyone working at our sites is
aligned with EnQuest's commitment to SAFE results.
2024 saw a number of changes to the EnQuest Board, with Jonathan Copus, our
Chief Financial Officer, formalising his Board position and Rosalind Kainyah
MBE and Marianne Daryabegui joining the Board as Non-Executive Directors. With
Salman Malik, Rani Koya and Liv Monica Stubholt stepping down as Directors at
the Annual General Meeting ('AGM'), I would like to thank them for their
diligent contributions to EnQuest over the years. I look forward to working
with the refreshed Board as we execute our growth strategy.
2025 performance and outlook
In 2025 our focus is to maximise the value of our existing assets, while using
our operating expertise and advantaged UK tax position to grow our business
through acquisition. Success in these goals is expected to deliver a
step-change in our operations, which will expand cash flow and enable us to
boost shareholder distributions and accelerate our growth in South East Asia.
Group production to the end of February from the current portfolio, excluding
Vietnam, was 43,037 Boepd, and net debt at 28 February 2025 equalled $371.7
million. At the same date, following the Group's year-end RBL redetermination,
cash and available facilities had risen to $549.0 million.
Our full-year 2025 net production guidance of between 40,000 and 45,000 Boepd
includes pro forma volumes from our Vietnam acquisition (due to complete
during the second quarter of 2025) and the expected impact of drilling and
well work at Magnus and PM8/Seligi.
Pro forma operating costs are expected to be c.$450.0 million, while capital
expenditures are expected to be c.$190.0 million. Decommissioning expenditures
are expected to total c.$60.0 million.
In 2025 we are working to advance several important projects toward Final
Investment Decisions ('FID'). Development of Bressay's gas cap will lower
Kraken costs and emissions, whist de-risking the pathway to development of
significant oil volumes on the Bressay and Bentley fields (together c.250
MMboe MMboe of the Group's 2C Resources).
Following encouraging testing, we also aim to progress the Kraken Enhanced Oil
Recovery ('EOR') project to a FID within the next 12 months. Initial estimates
suggest that this has potential to unlock 30 to 60 MMbbls gross of additional
recoverable oil.
Our position as a top quartile operator, alongside our advantaged UK tax
position, 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 and deployed across other geographies as we continue to grow and
diversify internationally.
Reflecting on 2024, I am proud of the resilience, adaptability, and commitment
that have defined our performance. Despite a dynamic and volatile global
energy landscape, EnQuest has delivered diversified growth, demonstrated
operational excellence, and returned capital to our shareholders. Our
employees remain the cornerstone of our success and, together, we recognise
the responsibility we share in shaping the future of energy.
As we look to execute a transformative transaction in the UK, and further
diversification of our portfolio, we will continue to be guided by a
commitment to generating value for our shareholders.
Operational review
2024 saw the Group deliver 90% production efficiency across its operated
portfolio. EnQuest is proud of its differentiated operating capability, with
its foundation in late-life asset management expertise and expansion to
include sector-leading decommissioning performance.
The Group is committed to optimising all of the assets we operate and has a
strong track record in extending the life of mature oil and gas fields. We do
this by applying focus to maintenance, key production equipment and through
the high-quality execution of drilling and well intervention work.
We are also focused on the decarbonisation of our portfolio and have several
projects in flight at Magnus, Kraken and the Sullom Voe Terminal ('SVT'),
aimed at significantly reducing the Group's carbon footprint and delivering an
improved long-term operating cost base. These components are key to ensuring
our operations continue to thrive in an evolving regulatory environment.
All the skills outlined above are transferable across our business and can be
deployed as we grow, in both the UK and in South East Asia, and as we
right-size and repurpose existing infrastructure to create a decarbonisation
and renewable energy hub at SVT.
In delivering production uptime of 90% across its operated portfolio during
2024, EnQuest achieved a level of performance which sits at the very top end
of the UK North Sea sector.
The latest available benchmarked data from the North Sea Transition Authority
('NSTA') shows that production efficiency across the UKCS is 77%. EnQuest's UK
operated asset uptime was 88%.
Further, the NSTA UKCS production efficiency for floating hubs is 71%. At
95.5% production efficiency, EnQuest's Kraken FPSO beats that by almost 25%.
This exemplary uptime performance extends to the Group's South East Asia
business, with 94% uptime at PM8/Seligi.
2024 UK operations performance summary
Production of 32,587 Boepd across EnQuest's UK upstream assets was underpinned
by strong production efficiencies across the portfolio and the Group's
investment in low-cost, quick-payback well work and production optimisation,
partially offsetting the impact of natural field declines.
Kraken
2024 performance summary
The Kraken Floating, Production, Storage and Offloading ('FPSO') facility
delivered an exceptional production efficiency of 96% (2023: 86%) and water
injection efficiency of 95.5% (2023: 85%) for the year, resulting in average
2024 net production of 12,759 Boepd (2023: 13,580 Boepd). This is a testament
to the focus and collaboration between the EnQuest and Bumi Armada operational
teams, delivering production efficiency performance that is 24.5% above the
industry average benchmark for floating hubs (as measured against the latest
North Sea Transition Authority data).
The Kraken maintenance shutdown was completed in ten days (six days full
shutdown and four days on single train operations). This work included the
five-yearly FPSO swivel inspection.
The Group continues to optimise Kraken cargo sales through the shipping fuel
market. Kraken oil is a key component of International Maritime Organization
('IMO') 2020 compliant low-sulphur fuel oil and, avoiding refining-related
emissions.
2025 outlook
The asset team is focused on maintaining best-in-class FPSO production
efficiency through focused investment in maintenance and reliability
activities. Work is ongoing to mature the Kraken Enhanced Oil Recovery ('EOR')
project to a Final Investment Decision ('FID') within the next 12 months. EOR
represents a material upside to Kraken's value, with base case incremental
recoverable oil estimates of 30 to 60 MMbbls gross.
The EnQuest team is advancing a gas import project that involves the subsea
tie-back of a Bressay gas well to the Kraken FPSO. By establishing an
alternative fuel supply to the diesel currently used to power Kraken
operations, this project has the potential to drive a step change reduction in
FPSO emissions and operating costs. It is anticipated that the Bressay gas
well can be drilled as part of an expanded well programme, alongside the
resumption of drilling at Kraken and a subsea well plugging and abandonment
programme.
With c.33 MMboe of 2C resources, the Group remains well positioned to pursue
infill drilling opportunities in the main Kraken field reservoir. Plans for
these activities will be advanced in parallel with the EOR project. In 2025,
Kraken production will be subject to natural field decline and the impact of a
15-day maintenance shutdown planned in the third quarter of the year.
Magnus
2024 performance summary
In 2024, Magnus celebrated 40 years of operations. Asset production efficiency
was 83% (2023: 88%) and the annual maintenance shutdown was completed in 18
days (versus the original 21-day plan) with all major scopes executed. The
shutdown involved 10,000 manhours of work being completed with zero lost-time
incidents.
Production of 14,173 Boepd was 11% lower than 2023 (15,933 Boepd), due to a
break in the infill drilling programme to accommodate the five-yearly rig
recertification scope which was undertaken in the first half of the year, and
incurred minor delays. Some of the planned well intervention also required rig
remediation, which resulted in wells being offline for longer than originally
planned. The Magnus team partially offset these losses through a successful
gas lift optimisation campaign (which added incremental production of 1,000
Boepd) and through improving water injection sweep (which delivered a 2%
reduction in overall Magnus field water cut through the year). In the fourth
quarter, an unplanned outage of the Magnus subsea isolation valve within
third-party-operated export infrastructure shut in all system users, including
Magnus production. Production was reinstated within seven days following a
collaborative response by all users with EnQuest operating the repair
activities.
EnQuest remains focused on the efficient management of key Magnus topside
infrastructure and targeted investment to optimise equipment reliability,
reduce obsolescence and continue to deliver top quartile operational uptimes.
2025 outlook
The Group plans to execute an infill drilling programme and
production-enhancing well intervention campaign at Magnus. The asset team is
also focused on enhancing water injection and reservoir sweep, including
progressing the conversion of a high water cut production well to water
injection. This is expected to increase reservoir pressure and boost
production. Looking beyond this programme of work, Magnus 2C resources of c.28
MMboe offer additional significant low-cost, quick-payback drilling and well
intervention opportunities.
The Group plans a two-day production outage in the third quarter of 2025,
aligned to a planned maintenance shutdown in third-party operated export
infrastructure. The asset team is also progressing the Ninian bypass project
towards FID in 2025. This involves the subsea bypass of the Ninian Central
Platform which is planned for cessation of production in 2027. Alongside
ongoing work at the Sullom Voe Terminal on the New Stabilisation Facility,
this project will secure a long-term export pathway for Magnus oil.
Following the initiation of the Magnus Flare Gas Recovery project in Q4 2024,
engineering work will continue in 2025. This project demonstrates EnQuest's
commitment to the decarbonisation of its portfolio.
Greater Kittiwake Area
2024 performance summary
At the Greater Kittiwake Area ('GKA'), 2024 production averaged 2,009 Boepd
(2023: 2,412 Boepd), largely in line with expectations. Solid operational
performance in the year was underpinned by production efficiency of 77% (2023:
83%) and included the efficient completion of the planned maintenance
shutdown.
2025 outlook
EnQuest and its partners are focused on extending field life and executing an
efficient glide path to decommissioning, including plans for early plugging
and abandonment of platform wells prior to cessation of production. This
process will be managed in full by EnQuest, with Shell transferring its
decommissioning operator role to EnQuest during 2024. A 14-day maintenance
shutdown is planned at GKA during Q3 2025.
Non-operated North Sea assets
2024 performance summary
2024 production across the Group's non-operated UK interests averaged 3,646
Boepd (2023: 4,450 Boepd). The 2023/24 platform drilling programme at Golden
Eagle concluded in August 2024. Two of the three planned producers were
successfully brought online alongside the planned water injector, although
overall production rates were below expectations.
At Alba, performance continued in line with the Group's expectations.
2025 outlook
At Golden Eagle, a 15-day shutdown is planned during the third quarter. The
operator also plans to execute well intervention work in the form of mud acid
stimulations in June.
At Alba, a more extensive shutdown of 28 days is planned.
2024 SOUTH EAST ASIA performance summary
PM8/Seligi, Malaysia
2024 performance summary
In 2024, EnQuest was awarded two accolades at the Malaysia Upstream Awards,
including Operator of the Year and Excellence in HSE. To be recognised in this
way by PETRONAS was extremely gratifying and is testament to the work
undertaken across the EnQuest Malaysia team.
Malaysian production averaged 8,149 Boepd, 10% higher than 2023. This increase
was driven by continued operational excellence and production efficiency of
94% (2023: 90%), benefitting from the availability of all compression units
throughout the year. 2024 volumes include 1,978 Boepd associated with Seligi
1a gas, to which Petronas holds the entitlement, and EnQuest receives a gas
handling and delivery fee.
The Group successfully executed a three-well infill drilling programme during
2024, with realised production rates in line with expectations. Three well
workovers were also completed, and the Group continued work on the PM8/Seligi
idle well restoration programme. Six wells were plugged and abandoned in
accordance with the planned decommissioning programme. The 2024 shutdown was
completed during the third quarter of 2024, with all critical integrity and
maintenance works, including a turbine control panel upgrade, delivered on
schedule.
EnQuest continued its excellent HSE performance in Malaysia during 2024,
reaching the milestones of two years and 4.9 million man hours worked without
a lost time incident.
2025 outlook
The Group plans to drill four infill wells during 2025, targeting undrained
oil in step-out areas of the main reservoir and undeveloped minor reservoirs.
The asset team is also targeting delivery of a well workover, with eight wells
to be plugged and abandoned. The drilling rig and workover unit will mobilise
during the first quarter of the year.
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.
EnQuest has significant 2P reserves and 2C resources of c.36 MMboe and c.28
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 Peninsular Malaysia demand.
Malaysia growth
Delivering portfolio diversification
Building on a decade of successful operations in Malaysia, EnQuest was awarded
the DEWA Production Sharing Contract ('PSC') and will be operator of the block
with largest participating interest of 42.0%.
The DEWA PSC consists of 12 discovered fields in an area c.50 kilometres off
the coast of Sarawak, in water depths of 40 to 50 metres. The block is in a
proven hydrocarbon area containing undeveloped discoveries, providing low-cost
development options to provide gas supply into the Sarawak gas system.
Within the initial two-year pre-development term of the PSC, EnQuest and its
partners will complete a resource assessment and submit a Field Development
and Abandonment Plan for the cluster of fields, which could hold up to 500
Bscf of gas in place, with the potential to deliver production of c.100 mmscf
per day (c.18 Kboed).
In addition, the Group was awarded an expansion to its Seligi gas agreement,
with the award to develop an additional 155 Bscf (c.27 million barrels of oil
equivalent) of non-associated Seligi field gas resources.
The agreement enables EnQuest and its partners to develop and commercialise
the non-associated gas resources in the PM8E PSC contract area and, in line
with expected demand, supply around 70 mmscf per day of sales gas. With a 50%
equity share, this represents c.35 mmscf per day net to EnQuest, which equates
to c.6,000 Boepd.
EnQuest will produce the additional gas by modifying its existing
infrastructure, with low levels of development capex required to deliver new
volumes into the Peninsular Malaysia gas system, helping the nation meet its
increasing energy needs. With first gas from the project expected in 2026,
these volumes will increase the gas component of EnQuest's production, which
aligns to the Group's strategic aim to reduce its overall carbon intensity.
Delivering diversified growth - Vietnam new country entry
In January 2025, EnQuest signed a Sale and Purchase Agreement to acquire
Harbour Energy's business in Vietnam, which includes the 53.125% equity
interest in the Chim Sáo and Dua production fields. This transaction aligns
with the Group's strategic aim to grow its international operating footprint
by investing in fast-payback assets, with low capex and reduced carbon
intensity.
The transaction has an effective date of 1 January 2024 and is scheduled to
complete during the second quarter of 2025. The headline value of the
transaction is $84 million and, net of interim period cash flows, the
consideration to be paid by EnQuest on completion is expected to equal c.$35
million. This fully staffed new country entry expands the Group's South East
Asian footprint beyond Malaysia, where EnQuest recently celebrated ten years
of successful operations.
EnQuest will operate the Chim Sáo and Dua fields ('Block 12W') from
completion, deploying its proven late-life and FPSO asset management expertise
to maximise value and progress discovered resources into reserves.
Block 12W is made up of three producing oil and gas fields; Chim Sáo, Chim
Sáo North West and Dua, located in the Nam Con Son Basin, approximately 400km
south west of Vung Tau, Vietnam. As at 1 January 2025, net 2P reserves and 2C
resources across the fields total 7.5 million Boe and 4.9 million Boe,
respectively. Block 12W production has responded positively to the drilling of
three infill wells during 2023 and a series of well interventions undertaken
in 2023-2024, with the combined impact of these scopes contributing c.3.0
MMboe to 2P reserves at 1 January 2025.
Net production in 2025 is forecast to average c.5.3 kboepd, with further
significant upside potential relating to well intervention performance. Oil
(c. 73% of output) is high quality and has historically realised a c.10%
premium to Brent. Gas is commercialised via an Associated Gas Gathering
Agreement. Field volumes are produced at a life of field asset breakeven of
c.$40 per Boe, with minimal capital requirements and a decommissioning
liability that is covered via a PSC fund. The resulting free cash flow
underpins Chim Sáo and Dua's value, making them strong anchor assets for
EnQuest's entry into Vietnam.
The Block 12W Production Sharing Contract runs to November 2030, with an
opportunity to extend the contract. Additional Block 12W prospectivity is
spread across gas discoveries and several additional targets; potential upside
that EnQuest intends to investigate.
As a country, Vietnam has significant potential for oil and gas development
beyond its established 4.4 billion Boe reserves, with an increase in
exploration in the hydrocarbon-rich South China Sea driving projects which
seek to replace the production from mature offshore fields. In addition, there
is significant opportunity for late-life asset managers, such as EnQuest, to
acquire producing assets as established operators have PSCs nearing their end
dates.
Decommissioning
Performance summary
For EnQuest's dedicated decommissioning team, 2024 represented another year of
sector-leading delivery; further enhancing the Group's strong track record of
executing multi-asset abandonment campaigns. With the majority of well plug
and abandonment ('P&A') activity completed significantly faster and
cheaper than sector averages, the Thistle and Heather project teams are
focused on the culmination of the respective projects. Work is underway ahead
of the 2025 preparation and removals programmes at these two major North Sea
platforms.
Recognising EnQuest's ability to deliver SAFE Results, exemplary
decommissioning performance and cost and schedule efficiencies, the Greater
Kittiwake Area ('GKA') joint venture has appointed EnQuest as operator for the
full GKA decommissioning scope, with Shell transferring its decommissioning
management role to EnQuest. The GKA infrastructure is expected to continue
production into the late 2020s, with EnQuest proactively planning for well
P&A activity to be completed alongside asset production. This approach
will result in a managed glidepath for the asset and will help EnQuest to
optimise the post cessation of production decommissioning programme.
Well decommissioning
At both the Heather and Thistle fields, the extensive programme of well
P&A continued at pace throughout the year. The Thistle team successfully
abandoned 11 wells during 2024, with a further well nearing completion at year
end. At Heather, 11 wells were completed by year end, resulting in the
completion of all abandonment work to Phase 2 and the commencement of the
final well decommissioning scope, Phase 3 conductor recovery.
In addition to the completion of 22 well abandonments across the two platform
rigs, the Thistle project team continued to implement a third activity string,
in the form of a conductor pulling unit ('CPU') to execute the recovery of
conductors on available wells. This resulted in a further 17 wells being
abandoned to the final stage of the well P&A process, taking Thistle to a
total of 24 wells fully abandoned.
Both the Thistle and Heather project teams are targeting completion of their
well P&A campaigns during 2025.
The Heather team aims to permanently disembark the platform in the second
quarter of 2025, while Thistle is scheduled for disembarkation early in 2026.
Both projects remain in line with the respective removals contract dates, with
Heather topside removals commencing during 2025 and Thistle topside removals
scheduled in 2026.
Throughout 2024, EnQuest has also progressed planning and 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
Alongside the completion of Phase 1 and Phase 2 abandonment work, the Heather
project team successfully completed the flushing of the gas import and oil
export pipelines, the cutting and laydown of the five Broom flexible risers
and, through close collaboration with Allseas, ensured the safe execution of
all platform preparatory works on Heather. This primarily involved the welding
of necessary lifting points underdeck and separation of topsides pipework from
the jacket to support future topsides removal.
The Heather team is fully focused on safe disembarkation of the asset, with
the key scope being the completion of the topsides cleaning and utility
rundown. This will be followed by the necessary leg-cutting works before the
arrival of the Pioneering Spirit heavy lift vessel during the summer of 2025
to lift and remove the topsides and transport to Denmark for safe disposal.
At Thistle, the project team continued to demonstrate its capability to
deliver multiple key scopes simultaneously. EnQuest and Saipem teams have
worked closely together, progressing engineering and planning for the
nine-month pre-disembarkation preparation phase in 2025 and the future topside
and jacket heavy lift campaigns. An extensive module void inspection campaign
was successfully completed which involved accessing, inspecting and clearing
43 void spaces. Subsea campaigns were also completed covering essential
inspection, repair and maintenance activities and preparatory work for future
conductor removal activities using bespoke tooling developed with the subsea
contractor.
Underdeck scaffold removal and key topside modifications were all completed
efficiently and on schedule.
2025 marks the final full year on the platform, with disembarkation planned
for early 2026. Key milestones for the year focus on completion of the main
rig and conductor pulling units campaigns, completion of topside steam
cleaning and pipeline flushing activities, and commencing and completing the
removal preparations prior to disembarkation.
Asset removals
With significant Engineering, Preparation, Removal and Disposal ('EPRD')
contracts in place for both Heather and Thistle, planning, engineering and
preparatory works have been executed at pace during 2024.
2025 will see the culmination of significant work through the removal of the
Heather topsides from field by Allseas and their Pioneering Spirit heavy lift
vessel. The Heather jacket is scheduled for removal in 2027, which aligns with
our agreed contractual execution windows.
Midstream
Safe, stable operations
Throughout 2024, 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 100% uptime for West of
Shetland gas. In addition, the SVT power station achieved 100% power delivery
throughout the period. The terminal continued to deliver strong HSE
performance, effectively managing the increase in project personnel on-site
throughout the year. During 2024, the milestones of five years, and five
million work hours Lost Time Incident ('LTI') free were reached, underlining
EnQuest's commitment to safety. A subsequent LTI at the terminal enabled the
team to review the circumstance and to ensure that mitigations and lessons
learned were incorporated into reinforcing the HSE Management System.
Decarbonisation
The Group is focused on right-sizing SVT for future operations. During 2024,
EnQuest successfully commenced Engineering, Procurement and Construction on
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
the aggregated impact of these two projects is expected to transform the
carbon footprint and overall emissions from SVT and the EQUANS-operated Sullom
Voe power station. The delivery of these scopes will reduce the Terminal's
operating costs and provide resilience for long-term operations through the
replacement of obsolete equipment. Together, these projects provide the
opportunity to extend production at both East of Shetland and West of Shetland
assets.
In 2024, EnQuest commenced the phased, partial decommissioning of redundant
processing and storage facilities at SVT. This scope has reduced the risk
potential at the site, along with reducing ongoing operating costs.
Furthermore, the removal of the facilities creates the opportunity to
repurpose areas of SVT for third-party use, including renewable energy
projects.
2024 emissions at SVT were elevated due to issues encountered with the site's
gas compression system, which resulted in flaring above the routine baseline
levels. In September, an engineering solution was deployed effectively,
restoring the compression system to full operations. This has resulted in a
return to lower process flaring and emissions.
People and community
EnQuest continues to build its community investment on Shetland with
contributions to local charities and sports groups, and through its workforce
development programmes.
The Group has a well-established apprentice programme at SVT, with three
apprentices successfully graduating in 2024. The Group also continued with its
graduate programme in 2024, with one graduate recruited into SVT.
SVT supported a range of cultural and sporting events on Shetland in 2024,
including Shetland Rugby's mid-summer event for children, women and men's
matches, the Shetland Junior Golf Open and sponsorship of local table tennis
events.
EnQuest also sponsored a Sail Training Shetland event for 70 young people from
Shetland to Bergen and provided support to the Shetland Folk Festival.
Seven educational awards for the academic year 2023-2024 were made by the
Trustees of the Sullom Voe Terminal Participants' Tenth Anniversary Fund. Now
in its 36th year, the Trust was established to promote and encourage the
education of Shetland residents who will be studying a discipline likely to
contribute to the social or economic development of Shetland. This year,
students are engaged in disciplines as wide-ranging as medicine, primary
education, folk and traditional music, geography and sustainable development.
As terminal operator, EnQuest also offers a scholarship to a student studying
in a technical or commercial discipline that is relevant to SVT, where they
take part in a work placement at the terminal during the summer break.
Veri Energy
Veri Energy is a wholly owned subsidiary of EnQuest, focused on transforming
skills and infrastructure to deliver economic decarbonisation solutions,
initially at the Sullom Voe Terminal ('SVT') on Shetland. Veri Energy is
supporting the UK Government's Clean Power 2030 Action Plan and delivering
against the Scottish Government's Energy Strategy and Just Transition Plan.
Veri Energy is fuelling the UK's energy transition
Using the SVT site as a base, Veri Energy is looking to support further
industrial decarbonisation and future growth in the energy transition through
the execution of phased renewable energy developments.
Carbon capture and storage ('CCS')
Veri Energy continues to develop a flexible, merchant-market carbon storage
solution that can transport and permanently store up to 10mtpa of CO(2) 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 four carbon storage licences as
part of the first round of UK carbon sequestration licences issued by the
North Sea Transition Authority ('NSTA'). Following work to assess the
licences, EnQuest took the decision to relinquish the Tern and Eider licences,
effective 1 March 2025. The remaining licence areas, CS013 and CS014, are some
99 miles northeast of Shetland and incorporate fields currently operated by
EnQuest, the Magnus and Thistle fields. These sites are large,
well-characterised deep storage formations connected by significant existing
infrastructure to the Sullom Voe Terminal on Shetland.
During 2024, work included significant engagement with the NSTA to progress
the licences through the early risk assessment phase, engaging with strategic
partners and refining the project development plan. Veri Energy continues to
be encouraged by the project's potential to be a low-cost merchant-market
solution for CO(2) emitters to permanently sequester carbon beginning in the
late 2020s/early 2030s.
Electrification
During 2024, Veri Energy identified an opportunity to develop an onshore wind
power project to assist in decarbonising and reducing costs at the Sullom Voe
Terminal, harnessing Shetland's natural advantage of one of the world's
highest wind capacity factors and existing terminal infrastructure. The
project underwent technical analysis, environmental impact assessment, and
feasibility studies during 2024, and is expected to enter front-end
engineering and design during 2025.
E-Fuels
Veri Energy continues to evaluate a multi-stage green hydrogen and derivatives
project at Sullom Voe. During 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. The company
continues to evaluate scenarios for end products, scale, partnerships and
technology integration for the project.
The favourable conditions for development of net-zero e-fuels at SVT, via the
combination of green hydrogen and biogenic CO(2), place Veri Energy at the
forefront of plans to produce e-diesel that can displace demand for fossil
fuels from the local marine and power industry. Powered by a skilled local
workforce and supported by the advantaged conditions at the terminal site,
there is the potential to scale this business for e-fuel export.
Financial review
Introduction
EnQuest delivered significant progress against each of its financial
priorities in 2024, and this momentum has continued into 2025. The Group has
optimised its capital structure and maximised available financial capacity for
value-accretive growth, by successfully tapping its high yield bond and the
repayment in full of both the reserve based lending ('RBL') and term loan
facilities.
EnQuest net debt was reduced by $95.1 million, to $385.8 million. This
reflects robust free cash flow generation, cash received from the farm-down of
Bressay and returns to shareholders through the share buy-back programme.
EnQuest maintained a strong focus on disciplined and efficient capital
expenditure and cost control. The investment in the future decarbonisation of
Magnus through the installation of a flare gas recovery system reflects our
focus on fast payback projects, while the re-certification of the Magnus
platform drilling rig underpins ongoing low-cost drilling and well
intervention work. As anticipated, EnQuest's increased share of throughput at
the Sullom Voe Terminal ('SVT') led to higher tariff costs in the period,
noting future cost and emission reductions are expected at the completion of
the ongoing decarbonisation projects at the terminal.
In line with the Group's growth strategy, EnQuest signed several agreements in
South East Asia: entering Vietnam through the acquisition of Block 12W;
extending the Group's Malaysian footprint with the expansion of the Seligi gas
agreement; and award of the DEWA PSC. These transactions provide geographic
and commodity diversification, adding production and reserves.
The Group reported an IFRS post-tax profit of $93.8 million for the year to 31
December 2024 (2023: IFRS post-tax loss of $30.8 million). This was primarily
driven by a lower tax charge in the period (reflecting fast payback investment
and the recognition of an additional deferred tax asset associated with
ring-fence expenditure supplement in the UK) offset by lower profit before tax
(production was lower year-on-year and tariffs were higher).
EnQuest's year-end RBL redetermination expanded the leverageable capacity of
the Group's assets, and at 28 February 2025 total cash and available
facilities totalled $549.0 million (31 December 2023: $498.8 million). With
the UK Autumn Budget Statement (30 October 2024) bringing clarity on the
fiscal landscape of the UK North Sea, EnQuest's strategic UK tax advantage and
financial capacity mean the Group remains well placed to pursue further growth
opportunities in the North Sea and internationally. EnQuest's Board is also
proposing a final dividend of 0.616 pence per share, equivalent to c.$15
million.
Income statement
Revenue
Group production averaged 40,736 Boepd (7.0% lower than in 2023, 43,812
Boepd), with strong uptime performance of c.90% across the operated portfolio
and investment in low-cost, quick-payback well work and production
optimisation partially offsetting the impact of natural field declines across
the portfolio. Oil accounted for 87.2% of this output (2023: 90.0%).
Brent crude oil prices declined 2.4% year-on-year to average $80.5/bbl (2023:
$82.5/bbl) while the average day-ahead UK gas price decreased by 15.5% to 83.6
GBp/therm (2023: 98.9 GBp/therm). Excluding the impact of hedging, EnQuest
realised an average oil price of $81.3/bbl (2023: $82.2/bbl). Post-hedging,
the realised oil price was $80.2/bbl (1.5% lower than in 2023, $81.4/bbl).
Reflecting the above price and volume drivers, Group revenue in the period
totalled $1,180.7 million, a 20.6% reduction year-on-year (2023: $1,487.4
million). In this figure, oil contributed $1,020.3 million (9.5% lower
year-on-year, 2023: $1,127.4 million) and condensate and gas revenue
contributed $164.6 million (51.4% lower year-on-year, 2023: $339.0 million).
Gas revenue mainly relates to the onward sale of gas purchases from
third-party West of Shetland fields under the terms of the Magnus acquisition.
The contribution of these volumes to revenue is therefore offset through an
equal and opposite charge to cost of sales.
Tariffs and other income generated $2.6 million (2023: $1.3 million), which
includes income associated with the transportation of Seligi gas. Realised
losses on commodity hedges totalled $12.9 million, primarily reflecting the
cost of historic put options (2023: $11.3 million). Unrealised gains on open
commodity contracts (from mark-to-market movements) totalled $3.1 million
(2023: $28.5 million).
Note: For the reconciliation of realised oil prices see 'Glossary - Non-GAAP
measures' starting on page 70
Cost of sales
Cost of sales was $787.4 million which was 16.8% lower than in 2023 ($946.8
million).
Production costs were broadly flat, totalling $307.6 million ($20.6/Boe) but
operating costs increased by $35.6 million to $382.8 million. This rise was as
expected and reflected an increase to EnQuest's share of throughput at SVT.
Costs and emissions at the terminal are forecast to reduce on completion of
the current decarbonisation projects on site. With the combination of higher
tariffs and lower production volumes, unit operating costs (excluding hedging
losses) increased by 15.5% to $25.3/Boe (2023: $21.9/Boe).
2024 2023
$ million $ million
Production costs 307.6 308.3
Tariff and transportation expenses 70.5 41.7
Realised loss/(gain) on derivatives related to operating costs 4.7 (2.8)
Operating costs(1) 382.8 347.2
Charge/(credit) relating to the Group's lifting position and inventory 2.2 (4.2)
Other cost of operations 136.3 305.9
Depletion of oil and gas assets 263.3 292.2
Other cost of sales 2.8 5.7
Cost of sales 787.4 946.8
Unit operating cost(2,3) $/Boe $/Boe
- Production costs 20.6 19.3
- Tariff and transportation expenses 4.7 2.6
Average unit operating cost 25.3 21.9
Notes:
1 See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP measures' starting on page 70
2 Calculated using production on a working interest basis including
Seligi Associated Gas
3 Excludes realised loss/(gain) on derivatives related to operating
costs
The charge relating to the Group's lifting position and hydrocarbon inventory
for the year ended 31 December 2024 was $2.2 million (2023: credit of $4.2
million), with the Group in a net neutral lifting position across its asset
base at 31 December 2024 (2023: net underlift position $3.5 million).
The cost of Magnus third-party gas purchases that are sold on is reported
within 'other cost of operations'. These costs fell significantly to $125.7
million (2023: $294.0 million), due to reduced third-party volumes and lower
gas prices.
Depletion expense ($263.3 million) was 9.9% lower than 2023 ($292.2 million),
mainly reflecting lower production.
Impairment
In the year, the Group recognised a non-cash net impairment charge of $71.4
million (2023: $117.4 million). This charge reflected changes to the UK Energy
Profits Levy confirmed by the UK Government in its Autumn Budget (including
the planned two-year extension to 31 March 2030), lower short-term oil price
assumptions and changes to the production profile of the non-operated Golden
Eagle field, partially offset by production profile changes at the GKA hub and
a lower discount rate of 10.0% (2023: 11.0%).
Other income and expenses
The Group has recognised net other expense in the period of $4.7 million
(2023: net other expense of $19.6 million). The impact of both the unwind of
discount and other changes in fair value of Magnus contingent consideration
have been combined in other income and expenses following a review of market
practice. This required a $58.9 million charge for 2023 being reclassed from
finance costs. As such, 2024 incurred a net $15.9 million non-cash charge
driven by: the unwinding of discounting offset by changes in the near-term oil
price assumptions and production and cost profiles (2023: $10.8 million
non-cash income, driven by an increase in the discount rate applied offset by
the unwinding of discounting). Other items of other income and expense
include: $14.6 million charge relating to the termination of a drilling rig
contract following the Kraken joint venture's decision to defer near-term
infill drilling; a non-cash charge of $7.1 million due to a net increase in
the decommissioning provision of fully impaired non-producing assets (2023:
non-cash charge of $32.8 million); a foreign exchange gain of $10.0 million,
reflecting a favourable movement in the Sterling to US Dollar exchange rate
(2023: $11.8 million foreign exchange losses); and lease income of $16.5
million (2023: $12.1 million).
Other expenses also include costs associated with Veri Energy, which totalled
$1.7 million in the year (2023: $1.6 million).
Adjusted EBITDA
Adjusted EBITDA for the year totalled $672.6 million, down 18.4% compared to
the same period in 2023 ($824.7 million). This reduction reflects the lower
revenue associated with reduced production, as well as higher tariffs at SVT
(see detail above).
EnQuest's net debt to last 12-month adjusted EBITDA ratio at 31 December 2024
equalled 0.6x. This was in line with the prior year (31 December 2023: 0.6x).
Adjusted EBITDA 2024 2023
$ million $ million
Profit/(loss) from operations before tax and finance income/(costs) 311.5 397.4
Unrealised commodity hedge gain (3.1) (28.5)
Depletion and depreciation 269.3 298.3
Impairment charge 71.4 117.4
Net other expenses 36.2 25.1
Foreign exchange and UKA forward purchase losses 2.8 3.8
Change in well inventories (5.5) (0.6)
Net foreign exchange (gain)/loss (10.0) 11.8
Adjusted EBITDA(1) 672.6 824.7
Note:
1 See reconciliation of Adjusted EBITDA within the 'Glossary - Non-GAAP
measures' starting on page 70
Finance costs
EnQuest's overall net finance costs fell by 12.5%, to $144.9 million (2023:
$165.6 million). This reflected a significantly lower level of outstanding
loans and borrowings, resulting in a lower overall interest charge of $73.5
million (2023: $89.7 million). Partially offsetting this were higher
refinancing fees (2024: $19.3 million), including the accelerated amortisation
of remaining initial term loan fees of $2.9 million and the early redemption
fee of $4.7 million paid following the repayment in full of the term loan in
October 2024 (2023: $7.9 million).
Finance charges included the unwinding of discounting on decommissioning and
other provisions (2024: $31.2 million; 2023: $25.4 million). Lease liability
interest costs totalled $27.7 million (2023: $43.8 million), and there were
other interest and financial expenses of $7.8 million (2023: $5.3 million),
which primarily are the cost for surety bonds that provide security for
decommissioning liabilities.
Finance income increased to $14.5 million reflecting additional cash on
deposit and accrued interest on the RockRose vendor loan (2023: $6.5 million).
Profit/loss before tax
Reflecting the movements above, the Group's profit before tax was $166.6
million (2023: profit of $231.8 million).
Taxation
The 2024 tax charge of $72.8 million includes a current tax charge of $12.1
million (2023: $262.6 million, inclusive of a current tax charge of $185.6
million).
In the Autumn Statement on 30 October 2024, the UK government confirmed that
from 1 November 2024 the rate of the Energy Profits Levy ('EPL') would be
increased from 35% to 38%. It was also announced that EPL Investment
Allowances would be abolished from 1 November 2024 and that decarbonisation
relief would be retained but the rate of relief would be reduced from 80% to
66%. These changes increase the current year tax charge and deferred tax for
EPL by $42.2 million. The announcement to extend the EPL period to 31 March
2030 was however not substantively enacted until March 2025, which resulted in
there being no impact on the 31 December 2024 balance sheet. Had the extension
been enacted, the Group estimates an additional deferred tax liability of
$115.9 million would have been recognised (see note 6 for further
information).
The Group's effective tax rate for the period was a charge of 43.7% (2023:
113.3%).
EnQuest's strategic UK North Sea tax asset was estimated at $2,066.4 (gross)
million at 31 December 2024 (31 December 2023: $2,007.9 million (gross)). The
increase reflects the recognition of additional carried forward losses
associated with the ring-fenced expenditure supplement, partially offset by
utilisation against the Group's profits before tax.
Due to this tax position, no significant corporation tax or supplementary
charge is expected to be paid on UK operational activities for the foreseeable
future. The Group expects to continue to make EPL payments for the duration of
the levy, and EnQuest also pays cash corporate income tax on its Malaysian
assets.
Profit/loss for the period
EnQuest's total profit after tax was $93.8 million, which compares to a 2023
loss of $30.8 million.
Earnings per share
The Group's reported basic earnings per share was 5.0 cents (2023 loss per
share: 1.6 cents) and reported diluted earnings per share was 4.9 cents (2023
loss per share: 1.6 cents).
Cash flow, EnQuest net debt and liquidity
Driven by continued adjusted free cash flow generation in 2024 and the
repayment of a vendor loan provided to RockRose related to the 2023 Bressay
transaction, EnQuest net debt at 31 December 2024 totalled $385.8 million.
This was $95.1 million lower than the position reported at 31 December 2023
($480.9 million).
The movement in EnQuest net debt was as follows:
$ million
EnQuest net debt 1 January 2024 (480.9)
Net cash flows from operating activities 508.8
Cash capital expenditure (252.9)
Magnus profit share payments (48.5)
Net interest and finance costs paid (73.1)
Finance lease payments (130.1)
Repayment of vendor loan provided to RockRose 107.5
Share buyback (9.0)
Term loan early termination fee (4.7)
Other movements, primarily net foreign exchange on cash and debt (2.9)
EnQuest net debt 31 December 2024(1) (385.8)
Note:
1 See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP measures' starting on page 70
Reported net cash flows from operating activities for the year were $508.8
million. This was 32.5% below the comparative period of 2023 ($754.2 million).
This reduction reflects: higher cash tax payments totalling $97.3 million
(2023: $41.0 million, including a tax refund of $37.4 million); $17.7 million
unwind of the joint venture advance cash call received in 2023 ($39.5
million); one-off payments relating to the rig cancellation ($14.6 million)
and $8.5 million of funds released from escrow pending resolution of the final
arbitration decision in relation to a dispute with a third party supplier in
Malaysia; and lower gross profit, reflecting lower revenues and higher
operating costs. Clean of one-off impacts of the tax refund, joint venture
advance cash call movements, rig cancellation and contractor dispute payments,
year-on-year cash flow from operating activities was 18.9% lower.
Reported net cash flows used in investing activities decreased year-on-year by
$79.1 million, to $183.6 million (2023: $262.7 million). This principally
reflects: higher capital expenditures ($252.9 million - primarily related to
the Magnus five-yearly rig recertification work scope, Golden Eagle well
campaign, decarbonisation projects at SVT, and the emissions reducing flare
gas recovery project on Magnus (2023: $152.2 million)); offset by repayment of
a vendor loan provided to RockRose ($107.5 million; 2023: net nil cash flow
impact reflecting farm-down proceeds being offset by the vendor financing
facilities from EnQuest to RockRose (see note 18); the final Golden Eagle
acquisition costs paid in 2023 ($50.0 million); and lower Magnus profit share
payments (2024: $48.5 million; 2023: $65.5 million).
Cash outflow on capital expenditure is set out in the table below:
Capital expenditure 2024 2023
$ million $ million
North Sea 230.4 124.2
Malaysia 19.0 21.0
Exploration and evaluation 3.5 7.0
252.9 152.2
The Group utilised $352.9 million of cash in financing activities (2023:
$478.6 million). This included further net repayments of the Group's loans and
borrowings totalling $130.6 million (2023: $237.1 million), with EnQuest
repaying its RBL facility in full ($140 million) in the first quarter and, in
the fourth quarter, the entire $150.0 million term loan facility following the
successful conclusion of a $160.0 million tap of its high yield bond in
October. Following the RBL redetermination process at the end of 2024 and no
further drawdowns in the first quarter of 2025, $237.1 million of the RBL
facility remains available to EnQuest for future drawdown.
Interest costs on the Group's borrowings totalled $83.2 million (2023: $105.9
million) and an additional $130.1 million was paid in relation to finance
leases (2023: $135.7 million).
EnQuest also repurchased $9.0 million of shares as part of its share buyback
programme.
In aggregate, the Group's cash and cash equivalents decreased by $33.4 million
in 2024. This decrease was primarily driven by the repayment in full of the
Group's RBL facility and share repurchases made under EnQuest's share buyback
programme offset by the net cash inflow from the farm-down of Bressay and
adjusted free cash flow generation. Adjusted free cash flow generation in 2024
was lower than in 2023, reflecting lower revenues, higher capital expenditure,
partial unwind of the joint venture advance cash call received in 2023 and
one-off costs associated with the drilling rig cancellation and the dispute
with a third party supplier in Malaysia, partially offset by lower finance
charges.
EnQuest net debt 31 December 2024 31 December 2023
$ million $ million
Bonds 632.1 474.7
Senior secured debt facility ('RBL') - 140.0
Term loan - 150.0
SVT Working Capital Facility 33.9 29.8
Cash and cash equivalents (280.2) (313.6)
EnQuest net debt(1) 385.8 480.9
Note:
1 See reconciliation of EnQuest net debt within the 'Glossary - Non-GAAP
measures' starting on page 70
The Group ended the year with $280.2 million of cash and cash equivalents (31
December 2023: $313.6 million) and cash and available undrawn facilities of
$474.5 million (31 December 2023: $498.8 million). Subsequently, following the
most recent RBL redetermination process, EnQuest's cash and available
facilities have increased to $549.0 million at 28 February 2025.
Balance sheet
EnQuest's robust liquidity position enables the Group to continue delivering
its capital-efficient programmes of capital investment and pursue
transformational North Sea and International production acquisitions.
Assets
Total assets reduced by 5.4% to $3,562.6 million (31 December 2023: $3,765.8
million). Driving this were: Repayment of a vendor loan provided to RockRose
($107.5 million); a reduction of $33.6 million in the Group's deferred tax
asset; and lower cash and cash equivalents of $33.3 million.
Liabilities
Total liabilities reduced by 8.7% to $3,020.1 million (31 December 2023:
$3,309.0 million) reflecting continuing material debt repayments and
optimisation of the capital structure (the full outstanding principals of
$140.0 million on the RBL and $150.0 million for the term loan Facility were
repaid in the year, offset by an additional $160.0 million tap of the high
yield bond); lower tax liabilities, reflecting fiscally efficient investments
and cash tax payments in the period, and a reduction in lease liabilities of
$86.9 million. Deferred tax liabilities increased by $27.1 million.
Contingent consideration payments in the period (related to the acquisition of
Magnus) totalled $48.5 million (2023: Magnus and Golden Eagle: $115.5
million). When combined with the net change in the fair value estimate, this
payment drove a lower outstanding contingent consideration estimate of $473.3
million (31 December 2023: $507.8 million).
Financial risk management
The Group's activities expose it to various financial risks, particularly
those associated with fluctuations in oil price, foreign currency risk,
liquidity risk and credit risk. The disclosures in relation to financial risk
management objectives and policies, including the policy for hedging, and the
disclosures in relation to exposure to oil price, foreign currency and credit
and liquidity risk, are included in note 27 of the Group's 2024 Annual Report.
Going concern disclosure
In recent years, EnQuest has focused on deleveraging and optimising its
capital structure, to simplify its balance sheet and maximise available
financial transactional capacity.
In 2024, the Group deleveraged further, reducing net debt by $95.1 million, to
$385.8 million at 31 December 2024. This was driven by robust adjusted free
cash flow generation and repayment of the first of two vendor loans that was
provided to RockRose as part of the 2023 Bressay farm-down. In the period
EnQuest fully repaid its Reserve Based Lending ('RBL') facility (from $140.0
million) and completed a $160.0 million tap of its high yield bonds. By using
this tap to repay a $150.0 million term loan facility, additional RBL capacity
was opened. At 31 December 2024, EnQuest's net debt to adjusted EBITDA ratio
was 0.6x. The Group ended 2024 with a positive RBL redetermination, which
expanded RBL capacity by 34%. Cash and available facilities at 28 February
2025 totalled $549.0 million.
Against this robust backdrop, EnQuest continues to closely monitor and manage
its funding position and liquidity requirements throughout the year, including
monitoring forecast covenant results. 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'). It is in line with EnQuest's production guidance (including the
acquisition and contribution of the Block 12W in Vietnam - completion expected
in the second quarter of 2025) and an oil price assumption of $75.0/bbl is
used for 2025 and 2026.
A reverse stress test has been performed on the Base Case. This indicates that
an oil price of c.$40.0/bbl is required to maintain covenant compliance over
the going concern period. The low level of this required price reflects the
Group's strong liquidity position.
The Base Case has also been subjected to further testing through a scenario
that explores the impact of the following plausible downside risks (the
'Downside Case'):
· 10.0% discount to Base Case prices resulting in Downside Case
prices of $67.50/bbl for 2025 and 2026;
· Production risking of 5.0%; and
· 2.5% increase in operating costs.
The Base Case and Downside Case indicate that the Group is able to operate as
a going concern and remain covenant compliant for 12 months from the date of
publication of its full-year results.
After making appropriate enquiries and assessing the progress against the
forecast, 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 2028. The viability assumptions are consistent with the going
concern assessment, with the extension of an oil price of $75.0/bbl for 2027
and 2028 in the Base Case. Consistent plausible downside risks have also been
applied in a Downside Case. This assessment has taken into account the Group's
financial position as at 26 March 2025, its future projections - including the
impacts of the Block 12W acquisition in Vietnam; the Seligi 1b gas agreement;
the Group's debt maturities, which occur towards the end of the viability
period; and the Group's principal risks and uncertainties. The Directors'
approach to risk management, their assessment of the Group's principal risks
and uncertainties, and the actions management are taking to mitigate these
risks, are outlined on pages 19 to 30. These risks and uncertainties include
potential impacts from climate change concerns and related regulatory
developments. The period of three years is deemed appropriate as it is the
time horizon across which management constructs a detailed plan against which
business performance is measured, and, given the Group's focus on short-cycle,
quick payback capital expenditures on its existing portfolio, is a time
horizon over which the Group can undertake any necessary mitigation
activities.
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 2028.
For the current assessment, the Directors also draw attention to the specific
principal risks and uncertainties (and mitigants) identified below, which,
individually or collectively, could have a material impact on the Group's
viability during the period of review. In forming this view, it is recognised
that such future assessments are subject to a level of uncertainty that
increases with time and, therefore, future outcomes cannot be guaranteed or
predicted with certainty. The impact of these risks and uncertainties has been
reviewed on both an individual and combined basis by the Directors, while
considering the effectiveness and achievability of potential mitigating
actions.
Oil price volatility
A decline in oil prices would adversely affect the Group's operations and
financial condition. To mitigate oil price volatility, the Directors have
hedged a total of 3.1 MMbbls from 1st April 2025 for the next 12 months with
an average floor price of $69.6/bbl and a further 1.3 MMbbls in the subsequent
12 month period with an average floor price of $68.3/bbl, in each case
predominantly utilising swaps. 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, such as the UK
EPL in recent years, can affect the Group's ability to access funding and
liquidity. The Group will continue to communicate to Government and Treasury
the importance of fiscal stability, whilst also monitoring 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
Group has evidenced its continued management of funding, prioritisation of
debt reduction and optimisation of its capital structure by fully repaying its
RBL and Term Loan along with obtaining additional unsecured funds through a
successful high yield bond tap in 2024. The increase in available funds under
the RBL following the recent redetermination and the long-dated maturity
profile of the Group's debt provide a material level of funding for the
majority of the viability period. Refinancing of the Group's current debt
structure (see note 17) is assumed towards the end of the viability period but
would likely occur well ahead of the 2027 bond maturities, providing funding
beyond the viability period.
In assessing viability, the Directors recognise that in a Downside Case
additional liquidity would be required towards the end of the viability
period, which may necessitate limited mitigations, such as working capital
management, amendments to capital work programmes, asset farm-downs or other
financing options, including vendor financing or prepayments. 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 2028.
Accordingly, the Directors therefore support this viability statement.
EnQuest oil and gas reserves and resources
North Sea South East Asia Total
Oil and NGLs Gas Total Oil and NGLs Gas Total Oil and NGLs Gas Total
MMbbls Bcf MMboe MMbbls Bcf MMboe MMbbls Bcf MMboe
2P reserves (working interest)1,2,3,5,6
1 January 2024 135.2 65.5 146.5 25.4 16.9 28.4 160.7 82.3 174.9
Revisions(4) (1.0) (7.1) (2.2) (3.4) 77.5 10.0 (4.3) 70.4 7.8
Production (11.0) (5.2) (11.9) (2.0) (0.6) (2.1) (13.0) (5.8) (14.0)
31 December 2024 123.3 53.1 132.4 20.1 93.8 36.3 143.3 146.9 168.6
2C resources (working interest)1,2,7,8
1 January 2024 305.1 18.1 308.2 31.1 287 80.6 336.2 305.1 388.8
Revisions, additions and relinquishments 0 0 0 (13.3) (126.8) (35.2) (13.3) (126.8) (35.2)
31 December 2024 305.1 18.1 308.2 17.8 160.2 45.4 322.9 178.3 353.6
Notes:
1 Reserves and resources are quoted on a working interest basis
2 2P reserves and 2C resources 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
4 Includes expansion of Seligi gas agreement in Malaysia
5 The above proven and probable reserves include volumes that will
be consumed as fuel gas, including c.6.4 MMboe at Magnus, c.0.7 MMboe at
Kraken, c.0.2 MMboe at Golden Eagle and c.0.1 MMboe at Scolty Crathes
6 The above 2P reserves at 31 December 2024 on an entitlement basis
is 157 MMboe (North Sea 132 MMboe and South East Asia 25 MMboe)
7 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
8 2C contingent resources at 31 December 2024 include the volumes
associated with the Group's PSC award at DEWA in Malaysia, as well as the
relinquishment of the PM409 exploration licence
9 Rounding may apply
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 appropriate
returns, including capitalising on any opportunities that may present
themselves, and the continuing need to remain financially disciplined. This
combination drives cost efficiency and cash flow generation, facilitating
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. Senior
management 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 map and
controls review, 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 and Risk
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
sanction of major decarbonisation projects across its existing infrastructure,
as well as a suite of scalable renewable energy and decarbonisation projects
under the management of Veri Energy, a wholly owned subsidiary of the Group.
The Group is also conscious that, as an operator of mature producing assets
with limited appetite for exploration, it has only slight 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 can
mitigate against the potential impact of 'stranded assets' (being those assets
that are 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 and Risk 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, cognisant of the changes to the UK Corporate Governance Code during
2024 (and Provision 29 for future financial years), supported by the Audit
Committee and the Sustainability and Risk Committee, has reviewed the Group's
system of risk management and internal control for the period from 1 January
2024 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 and Risk Committee meeting in
support of this review. The Group will report on the updated UK Corporate
Governance Code 2024 changes as appropriate.
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 and
Risk Committee, which are now integrated into the Group's internal audit
programme for review. During the year, six Risk Bowties were reviewed,
ensuring that all 19 of the Group's identified risks have been reviewed within
the targeted three-year cycle.
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 conflicts in Western Europe or the Middle East,
although recognises that the situations have caused oil price volatility. The
Group continues to monitor its position to ensure it remains compliant with
any sanctions in place.
Climate change risks
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.
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
and gas price, financial, reputational and fiscal risk and government take,
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 through reducing Scope 1 and Scope 2 emissions from
existing operations. A decarbonisation strategy is being pursued through
EnQuest's wholly owned subsidiary, Veri Energy, which was established to drive
decarbonisation and renewable energy business opportunities.
The Group's risk appetite for climate change risk is reported against the
Group's impacted principal risks.
MITIGATION
Mitigations against the Group's principal risks potentially impacted by
climate change are reported later in this report.
The Group has an emissions management strategy and is committed to a 10%
reduction in Scope 1 and 2 emissions over three years against a rolling
year-end baseline. These targets are directly linked to organisation-wide
remuneration via the Group Performance Share Plan. The first three-year period
of emission reduction targets covered the 2023 out-turn versus a 2020
baseline, and in this period the Group achieved a reduction of 23% through
improvements in operational performance, minimising flaring and venting where
possible, and the application of appropriate and economic improvement
initiatives.
For 2024, the rolling emission reduction strategy shifted to a new baseline of
verified 2021 emissions and, when measured against this, the Group's year-end
2024 emissions achieved an 8.2% reduction against a year-end 2021 baseline,
falling short of the 10% emission reduction target. Exceptional
decarbonisation efforts in 2021 reduced baseline emissions by 16% compared to
2020, far surpassing the targeted 3% year-on-year reduction.
Looking ahead, EnQuest has initiated significant decarbonisation workstreams
across its existing portfolio, including a Flare Gas Recovery Project at
Magnus, the New Stabilisation Facility and long-term power solution at the
Sullom Voe Terminal ('SVT'), and the potential for a Bressay gas line to power
Kraken operations.
Following the establishment of Veri Energy during 2023, the Group's business
model incorporates a focus on repurposing existing infrastructure to support
its renewable energy and decarbonisation ambitions, centred around SVT.
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'.
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 and emerging risks facing
the Group at its February meeting, including those that would threaten its
business model, future performance, solvency or liquidity. Further to this
assessment, the Board has committed to reviewing its principal risks and
uncertainties during 2025 as part of its preparation for reporting against the
2024 changes to provision 29 of the Code.
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; 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 22),
and/or a materially lower than expected production performance for a prolonged
period (see 'Production' risk on page 22 and 'Reserves estimation and
replacement' on page 26), which could reduce the Group's cash generation,
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. Every employee is 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 2024, EnQuest's Lost Time Incident frequency rate(1) ('LTIF') of 1.55 and
two hydrocarbon releases challenged this objective. The lost time injuries
were all associated with routine repetitive tasks. 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. The hydrocarbon releases did not have common root causes and
occurred at two different locations. All events were subject to thorough
investigation and no systemic failure was identified within EnQuest systems.
All of the injurious events in 2024 were associated with external contractors,
reflecting the high level of project and decommissioning activities that rely
on these services. Regardless, the Group takes its responsibility seriously
and has provided additional resources to support contractors to ensure that
EnQuest's fundamental aim of ensuring no harm to people and respect for the
environment is given the highest priority.
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 which are
implemented on a prioritised risk basis. 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 and Risk
Committee. During 2024, 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 Energy Security and Net Zero,
and the Malaysian regulator, PETRONAS Malaysia Petroleum Management.
Potential impact
Medium (2023: Medium)
LIKELIHOOD
Medium (2023: Medium)
CHANGE FROM LAST YEAR
EnQuest respects the hazards associated with oil and gas development and
production in harsh environments and has applied continued focus to the safety
and wellbeing of its people and assets. As a result, the potential impact and
likelihood remains in line with 2023. 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
good 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 (2023: 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 64)
and the terms of the Group's RBL facility, which requires hedging of EnQuest's
entitlement sales volumes (see page 64). To mitigate oil price volatility, the
Directors have hedged a total of 3.1 MMbbls from 1st April 2025 for the next
12 months with an average floor price of $69.6/bbl and a further 1.3 MMbbls in
the subsequent 12 month period with an average floor price of $68.3/bbl, in
each case predominantly utilising swaps. 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.
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
against a low oil price environment.
Potential impact
High (2023: High)
Likelihood
High (2023: 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 (2023: 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 producing 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 and has recently added diversified growth to its production base
through an expansion of the Seligi gas agreement and the Group's agreement to
acquire the Block 12W production assets in Vietnam.
Potential impact
High (2023: High)
Likelihood
Medium (2023; Medium)
CHANGE FROM LAST YEAR
There has been no material change in the potential impact or likelihood. The
Group revised its 2024 production guidance to slightly below its original
guidance for the year 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 (2023: 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 RBL facility would 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 page 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.
MITIGATION
Balance sheet management remains a strategic priority. During 2024, the
Group's free cash flow generation and the repayment of a vendor loan provided
to RockRose as part of the 2023 Bressay transaction drove a $95.1 million
reduction in EnQuest net debt to $385.8 million at 31 December 2024, with the
EnQuest net debt to adjusted EBITDA ratio maintained at 0.6x. During the year,
EnQuest also further optimised its capital structure through the successful
high yield bond tap and repayment in full of both the RBL and Term Loan
facilities. Repayment of the term loan, which had second lien security, added
additional access to the RBL while the year-end 2024 redetermination resulted
in an increase to the available funds under the RBL. At 27 March 2025, 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 (2023: High)
Likelihood
Medium (2023: High)
CHANGE FROM LAST YEAR
There is no change to the potential impact but the likelihood has reduced.
Against a backdrop of improved fiscal certainty and relatively stable oil
price environment, the Group has significantly reduced its debt and
successfully refinanced certain of its debt facilities in 2024. This maximises
available financial capacity, with funds available under the Group's RBL
further increased in January 2025 following the annual redetermination process
(see the going concern disclosure on page 16).
However, factors such as climate change, other ESG concerns, oil price
volatility and geopolitical risks continue to impact investors' and insurers'
acceptable levels of oil and gas sector exposure. In addition, the cost of
emissions trading allowances may 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 (2023: 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, including drilling rigs for development
and decommissioning projects, and access to experienced and capable personnel.
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 approximately $2.1 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. Human Resources risk
is covered specifically on page 30.
Potential impact
High (2023: High)
Likelihood
High (2023: High)
CHANGE FROM LAST YEAR
The potential impact and likelihood remain unchanged, with the confirmed
changes of the UK EPL and removal of investment allowances 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. Operating in a competitive industry may
result in higher than anticipated prices for the acquisition of assets and
licences.
RISK APPETITE
Medium (2023: 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 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.
The Audit Committee has 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 2024.
A number of actions were undertaken to further strengthen our controls
including the following:
· Implementation of IT Governance, Risk and Compliance framework to
address UK Corporate Governance Code 2024
· Security strengthened through actions to improve privileged
access and password changes to finance system
· Insider threat penetration testing carried out, alongside a
ransomware threat and attack desktop exercise facilitated by a third party
cyber security company
· Air gapped (segregated) back-ups, meaning they are separately
available with minimal operational impact should the main data be hit by
ransomware. An added feature of this initiative is continuous scanning of all
EnQuest's back-ups for the presence of ransomware
· Established a Security Operations Centre for 24/7 live monitoring
of Group's cyber environment, improving cyber threat detection and
intervention capability
· Upgraded the Group's existing brand protection service to include
'Identity Protection' module. This is utilised to identify EnQuest IT users'
leaked credentials
· Initiated a review of the Group's supply chain/vendor cyber
security risk management environment, with 31 vendors assessed to date
· Established a Group-wide vulnerability management process,
enabling the continuous review and identification of high risk vulnerabilities
and planned remediation
Potential impact
Medium (2023: Medium)
Likelihood
High (2023: High)
CHANGE FROM LAST YEAR
There is no change to the impact or likelihood of this risk.
RISK APPETITE
Low (2023: Low)
Portfolio Concentration
RISK
The Group's existing 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
The Group is pursuing an international growth and diversification strategy
that includes an increased gas component with the extent of portfolio
concentration moderated by existing production generated in Malaysia and
further business development activities in South East Asia, including the
expansion of the Seligi Gas Agreement in Malaysia and agreement to acquire
hydrocarbon assets in Vietnam.
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.
This includes performing extensive due diligence (using in-house and external
personnel) and actively involving executive management and the Board 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, executing
development projects, expanding hubs and 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 the three key focus areas of carbon storage,
electrification/renewable power and production of e-fuels through its
subsidiary company, Veri Energy, which could provide diversified revenue
opportunities in the long term.
Potential impact
High (2023: High)
Likelihood
High (2023: High)
CHANGE FROM LAST YEAR
There has been no material change in the potential impact or likelihood
although the Group is expected to increase its exposure to gas, other
geographies and other sources of income over time.
RISK APPETITE
Medium (2023: Medium)
Reserves Estimation and Replacement
RISK
Failure to develop 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 peer-review process and, where
appropriate, external review and relevant stage gate processes. All reserves
are currently externally reviewed by a Competent Person.
The Group has material reserves and resources at Magnus, Kraken and
PM8/Seligi. Some of the resources volumes can be accessed through low-cost
workovers, drilling and tie-backs to existing infrastructure.
The Group continues actively to consider potential opportunities to acquire
new production resources and development projects that meet its investment
criteria. In 2024, the Group successfully secured the Seligi Phase 1b project
(13.7 MMboe net WI reserves) with anticipated first gas in 2026. Additionally,
the Group was awarded a Production Sharing Contract for a new discovered
resource opportunity block (DEWA) in Malaysia, which has the potential to be
developed in the next few years with estimated resources of 17.7 MMboe net WI.
The Group's acquisition in Vietnam is expected to complete in the second
quarter of 2025, adding 7.5 MMboe of net 2P reserves.
Potential impact
High (2023: High)
Likelihood
Medium (2023: Medium)
CHANGE FROM LAST YEAR
There is no change to the potential impact or likelihood of this risk. There
have been two new secured projects in Malaysia, Seligi Phase 1b and the DEWA
block. It is also expected that the Group will complete the acquisition of
Harbour Energy's asset in Vietnam in 2025 which will further improve the
Reserves Replacement Ratio.
Other aspects still remain, such as possible low oil prices and higher
development cost and declining asset performance which accelerate cessation of
production and can potentially affect development of contingent and
prospective resources and/or reserves certifications.
Given EnQuest's limited appetite for exploration, the Labour Government's
manifesto promise not to issue new oil and gas exploration licences in the UK
is not expected to have a material impact on the Group.
RISK APPETITE
Medium (2023: 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
infill development, tie-back and facility modifications, 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, near-field tie-backs
and facility modifications to enable emission reduction initiatives in its
Upstream business, industrialise decommissioning projects to ensure cost
efficiency and unlock new energy and decarbonisation opportunities through
innovative commercial structures and redevelopment of SVT. While the Group
necessarily assumes significant risk when it sanctions a new project (for
example, by incurring costs against oil price or cost of emission allowances
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 (2023: Medium)
Likelihood
Medium (2023: Low)
CHANGE FROM LAST YEAR
The potential impact remains 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. However, the volume of projects across the
portfolio in the execution phase, including the material right-sizing projects
ongoing at SVT, increase the likelihood of this risk impacting Group
operations.
RISK APPETITE
Medium (2023: 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
Given the Group's strategy to grow in the UK and internationally, including in
its nascent new energy business, 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 (2023: High)
Likelihood
Medium (2023: Medium)
CHANGE FROM LAST YEAR
There has been no material change in the potential impact or likelihood given
the enactment of the Labour Government's expected changes to the EPL.
RISK APPETITE
Medium (2023: Medium)
International Business
RISK
While the majority of the Group's activities and assets are in the UK, the
international business is still material and, with recent acquisitions, is
growing. 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 and product
mix); 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 conducts a
review of commercial, technical, ethical and other business risks, together
with mitigation and considers 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 (2023: Medium)
Likelihood
Medium (2023: Medium)
CHANGE FROM LAST YEAR
There has been no material change in the impact or likelihood. The Group's new
country entry into Vietnam is fully staffed, thus ensuring a continuation of
experienced, capable asset support.
RISK APPETITE
Medium (2023: 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 and 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 (2023: Medium)
Likelihood
Medium (2023: Low)
CHANGE FROM LAST YEAR
There has been no material change in the potential impact but the challenging
UK fiscal environment increases the likelihood of default for EnQuest's joint
venture partners.
RISK APPETITE
Medium (2023: 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,
ensuring that they comply with equivalent standards.
The Group requires adherence to its Code of Conduct and runs ethics and
compliance programmes to provide assurance on conformity with relevant legal
and ethical requirements. In 2024, the Group launched a Handrails website - a
standalone website with various ethics and compliance policies, complemented
by external training within the website.
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 operations 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 Risk Management Framework and acting with high standards of integrity.
The Group is successfully implementing this strategy.
Potential impact
High (2023: High)
Likelihood
Low (2023: Low)
CHANGE FROM LAST YEAR
There has been no material change in the potential impact or likelihood.
RISK APPETITE
Low (2023: 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, 2024 saw a further rise in the number of
young professionals joining EnQuest, and we saw a 33% increase in employees
under the age of 24. 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 in the UK 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 (2023: Medium)
Likelihood
Medium (2023: Medium)
CHANGE FROM LAST YEAR
There has been no material change in the potential impact or likelihood.
RISK APPETITE
Medium (2023: Medium)
PRODUCTION DETAILS
Average daily production on a net working interest basis 1 Jan 2024 to 1 Jan 2023 to
31 Dec 2024 31 Dec 2023
(Boepd) (Boepd)
UK Upstream
- Magnus 14,173 15,933
- Kraken 12,759 13,580
- Golden Eagle 3,328 4,199
- Other Upstream(1) 2,327 2,663
Total UK 32,587 36,375
Total Malaysia 8,149 7,437
Total EnQuest 40,736 43,812
(1) Other Upstream: Scolty/Crathes, Greater Kittiwake Area and Alba
KEY PERFORMANCE INDICATORS
2024 2023 2022
ESG metrics:
Group LTIF(1) 1.55 0.52 0.57
Scope 1 and Scope 2 Emissions (kilo-tonnes of CO(2) equivalent) 1,068.4 1,041.9 1,051.9
Business performance data:
Production (Boepd) 40,736 43,812 47,259
Unit opex (production and transportation costs) ($/Boe)(2) 25.3 21.9 22.7
Cash expenditures ($ million) 313.4 211.1 174.8
Capital(2) 252.9 152.2 115.8
Decommissioning 60.5 58.9 59.0
Reported data:
Cash generated from operations ($ million) 685.9 854.7 1,026.1
EnQuest net debt ($ million)(2) 385.8 480.9 717.1
Net 2P reserves (MMboe) 169 175 190
(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 70
Group Income Statement
For the year ended 31 December 2024
2024 2023
Notes $'000 $'000
Revenue and other operating income 4(a) 1,180,709 1,487,419
Cost of sales 4(b) (787,383) (946,752)
Gross profit/(loss) 393,326 540,667
Net impairment charge to oil and gas assets 9 (71,414) (117,396)
General and administration expenses 4(c) (5,702) (6,348)
Other (expenses)/income 4(d) (4,682) (19,550)
Profit/(loss) from operations before tax and finance income/(costs) 311,528 397,373
Finance costs 5 (159,422) (172,087)
Finance income 5 14,508 6,493
Profit/(loss) before tax 166,614 231,779
Income tax 6 (72,841) (262,612)
Profit/(loss) for the year attributable to owners of the parent 93,773 (30,833)
Total comprehensive profit/(loss) for the year, attributable to owners of the 93,773 (30,833)
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 7
Basic 0.050 (0.016)
Diluted 0.049 (0.016)
The attached notes 1 to 30 form part of these Group financial statements.
Group Balance Sheet
At 31 December 2024
Notes 2024 2023
$'000 $'000
ASSETS
Non-current assets
Property, plant and equipment 9 2,297,954 2,296,740
Goodwill 10 134,400 134,400
Intangible assets 11 20,563 18,323
Deferred tax assets 6(c) 506,481 540,122
Trade and other receivables 15 2,102 -
Other financial assets 18 38,459 36,282
2,999,959 3,025,867
Current assets
Intangible assets 11 1,138 876
Inventories 12 48,976 84,797
Trade and other receivables 15 230,971 225,486
Current tax receivable 1,256 1,858
Cash and cash equivalents 13 280,239 313,572
Other financial assets 18 69 113,326
562,649 739,915
TOTAL ASSETS 3,562,608 3,765,782
EQUITY AND LIABILITIES
Equity
Share capital and premium 19 392,054 393,831
Treasury shares 19 (4,425) -
Share-based payments reserve 13,949 13,195
Capital redemption reserve 19 2,006 -
Retained earnings 19 138,882 49,702
TOTAL EQUITY 542,466 456,728
Non-current liabilities
Loans and borrowings 17 621,440 747,812
Lease liabilities 23 288,262 288,892
Contingent consideration 21 452,891 461,271
Provisions 22 710,976 715,436
Deferred income 24 138,095 138,416
Trade and other payables 16 - 32,917
Deferred tax liabilities 6(c) 104,698 77,643
2,316,362 2,462,387
Current liabilities
Loans and borrowings 17 43,417 27,364
Lease liabilities 23 46,994 133,282
Contingent consideration 21 20,403 46,525
Provisions 22 55,130 79,861
Trade and other payables 16 414,390 347,409
Other financial liabilities 18 21,580 26,679
Current tax payable 101,866 185,547
703,780 846,667
TOTAL LIABILITIES 3,020,142 3,309,054
TOTAL EQUITY AND LIABILITIES 3,562,608 3,765,782
The attached notes 1 to 30 form part of these Group financial statements.
The financial statements were approved by the Board of Directors and
authorised for issue on 26 March 2025 and signed on its behalf by:
Jonathan Copus
Chief Financial Officer
Group Statement of Changes in Equity
For the year ended 31 December 2024
Notes Share capital Treasury Share-based Capital redemption reserve Retained Total
$'000 Share shares payments reserve $'000 earnings $'000
premium $'000 $'000 $'000
$'000
Balance at 1 January 2023 131,650 260,546 - 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 1,635 - - (1,635) - - -
Share-based payment - - - 3,320 - - 3,320
Balance at 31 December 2023 133,285 260,546 - 13,195 - 49,702 456,728
Profit for the year - - - - - 93,773 93,773
Total comprehensive income for the year - - - - - 93,773 93,773
Issue of shares to Employee Benefit Trust 19 229 - - (229) - - -
Repurchase and cancellation of shares 19 (2,006) - (4,425) - 2,006 (4,593) (9,018)
Share-based payment 20 - - - 983 - - 983
Balance at 31 December 2024 131,508 260,546 (4,425) 13,949 2,006 138,882 542,466
The attached notes 1 to 30 form part of these Group financial statements.
Group Statement of Cash Flows
For the year ended 31 December 2024
Notes 2024 2023
$'000 $'000
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations 29 685,946 854,746
Cash received from insurance - 5,190
Cash (paid)/received on purchase of financial instruments (10,306) (5,795)
Cash paid in relation to amounts previously provided for (9,063) -
Decommissioning spend (60,544) (58,911)
Income taxes paid (97,264) (40,986)
Net cash flows from/(used in) operating activities 508,769 754,244
INVESTING ACTIVITIES
Purchase of property, plant and equipment (249,165) (141,741)
Proceeds from farm-down 11,24 1,263 141,360
Vendor financing facility repaid/(loaned) 18(f),24 107,518 (141,360)
Purchase of intangible oil and gas assets 11 (3,686) (10,467)
Purchase of other intangible assets 11 (1,138) (876)
Payment of Magnus contingent consideration - Profit share 21 (48,465) (65,506)
Payment of Golden Eagle contingent consideration - Acquisition 21 - (50,000)
Interest received 10,100 5,895
Net cash flows (used in)/from investing activities (183,573) (262,695)
FINANCING ACTIVITIES
Proceeds from loans and borrowings 31,662 190,657
Repayment of loans and borrowings (162,304) (427,736)
Payment for repurchase of shares (9,018) -
Payment of obligations under financing leases 23 (130,065) (135,675)
Interest paid (83,162) (105,877)
Net cash flows (used in)/from financing activities (352,887) (478,631)
NET (DECREASE)/INCREASE IN CASH AND CASH EQUIVALENTS (27,691) 12,918
Net foreign exchange on cash and cash equivalents (5,642) (957)
Cash and cash equivalents at 1 January 313,572 301,611
CASH AND CASH EQUIVALENTS AT 31 DECEMBER 280,239 313,572
Reconciliation of cash and cash equivalents
Total cash at bank and in hand 13 226,317 313,028
Restricted cash 13 53,922 544
Cash and cash equivalents per balance sheet 280,239 313,572
The attached notes 1 to 30 form part of these Group financial statements.
Notes to the Group Financial Statements
For the year ended 31 December
2024
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 of the Group
Annual Report and Accounts.
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 2024 were
authorised for issue in accordance with a resolution of the Board of Directors
on 26 March 2025.
A listing of the Group's companies is contained in note 28 to these Group
financial statements.
2. Basis of preparation
The financial information for the years ended 31 December 2024 and 2023
contained in this document does not constitute statutory accounts of Enquest
plc (the Company), as defined in section 435 of the Companies Act 2006. The
financial information for the years ended 31 December 2024 and 2023 has been
extracted from the consolidated financial statements of Enquest plc and all
its subsidiaries (the Group), which were authorised by the Board of Directors
on 26 March 2025 and which will be delivered to the Registrar of Companies in
due course. The auditor's report on those financial statements was unqualified
and did not contain a statement under section 498 of the Companies Act 2006.
The consolidated financial statements have been prepared in accordance with
United Kingdom international accounting 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 2024.
For the year ended 31 December 2024, the Group removed the separate disclosure
of remeasurements and exceptional items from the presentation of the Group
income statement to simplify their presentation for users of accounts and
bring them more in line with peers. The Group continues to present various
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 the measurement basis
applied to 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 to aid the understanding of
the Group's underlying financial performance, balance sheet and cash flows by
adjusting for certain items, such as those previously classified as
remeasurements and exceptional items, which impact upon IFRS measures or, by
defining new measures. See the Glossary - Non-GAAP Measures on page 70 for
more information.
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.
Going concern
The financial statements have been prepared on the going concern basis.
In recent years, EnQuest has focused on deleveraging and optimising its
capital structure, to simplify its balance sheet and maximise available
financial transactional capacity.
In 2024, the Group deleveraged further, reducing EnQuest net debt by $95.1
million, to $385.8 million at 31 December 2024. This was driven by robust
adjusted free cash flow generation and repayment of the first of two vendor
loans that was provided to RockRose as part of the 2023 Bressay farm-down. In
the period EnQuest fully repaid its Reserve Based Lending ('RBL') facility
(from $140.0 million) and completed a $160.0 million tap of its high yield
bonds. By using this tap to repay a $150.0 million term loan facility,
additional RBL capacity was opened. At 31 December 2024, EnQuest's net debt to
adjusted EBITDA ratio was 0.6x. The Group ended 2024 with a positive RBL
redetermination, which expanded RBL capacity by 34%. Cash and available
facilities at 28 February 2025 totalled $549.0 million.
Against this robust backdrop, EnQuest continues to closely monitor and manage
its funding position and liquidity requirements throughout the year, including
monitoring forecast covenant results. 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'). It is in line with EnQuest's production guidance (including the
acquisition and contribution of the Block 12W in Vietnam - completion expected
in the second quarter of 2025) and an oil price assumption of $75.0/bbl is
used for 2025 and 2026.
A reverse stress test has been performed on the Base Case. This indicates that
an oil price of c.$40.0/bbl is required to maintain covenant compliance over
the going concern period. The low level of this required price reflects the
Group's strong liquidity position.
The Base Case has also been subjected to further testing through a scenario
that explores the impact of the following plausible downside risks (the
'Downside Case'):
· 10% discount to Base Case prices resulting in Downside Case prices
of $67.50/bbl for 2025 and 2026;
· Production risking of 5.0%; and
· 2.5% increase in operating costs.
The Base Case and Downside 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, 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:
· Supplier Finance Arrangements (Amendments to IAS 7 and IFRS 7)
· Classification of Liabilities as Current or Non-current and
Non-current Liabilities with Covenants (Amendments to IAS1)
· Lease Liability in a Sale and Leaseback (Amendment to IFRS 16)
Standards issued but not yet effective
At the date of authorisation of these financial statements, the Group has not
applied the following new and revised IFRS Standards that have been issued but
are not yet effective:
IFRS 9 and IFRS 7 Amendments to the Classification and Measurement of Financial Instruments
IFRS 18 Presentation of financial statements
IFRS 19 Subsidiaries without Public Accountability: Disclosures
Amendments to IAS 21 Lack of Exchangeability
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. The Directors noted IFRS 18 may change the presentation and
disclosure information in the financial statements when effective.
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 2024, 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 22,
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, valuation of contingent consideration and deferred
tax, as well as an acceleration of cessation of production and subsequent
decommissioning expenditure, 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 10 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 based on reserves and
resources to which it is considered probable that a market participant would
attribute value to them, operating costs, capital expenditure, decommissioning
costs, tax attributes, risking factors applied to cash flows, and discount
rates.
Details of impairment charges and reversals recognised in the income statement
and details on the carrying amounts of assets are shown in note 9, note 10 and
note 11.
The estimates for assumptions made in impairment tests in 2024 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 2024, the post-tax discount rate was
estimated at 10.0% (2023: 11.0%) reflecting the impact from the Group's
reduced debt position and clarity over the UK fiscal system.
Oil prices
The price assumptions used for FVLCD impairment testing were based on latest
internal forecasts as at 31 December 2024. These price forecasts reflect
EnQuest's 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 2023, with nearer-term prices reflecting current
market dynamics and 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.
When compared to the International Energy Agency's ('IEA') forecast prices
under its Announced Pledges Scenario ('APS'), which assumes all climate
commitments made by governments and industries around the world by the end of
August 2024 for both 2030 targets and longer-term net zero or carbon
neutrality pledges will be met in full and on time, EnQuest's short and
medium-term assumptions are below those assumed under the APS, while its
longer-term prices are slightly higher. When compared with latest available
Paris-consistent climate scenario modelling data released by the World
Business Council of Sustainable Development ('WBCSD'), EnQuest's assumption is
broadly aligned with the top end of a range of Paris-consistent scenarios. A
10% reduction in crude oil price assumptions, which management believes to be
a reasonably possible change as further considered later in this note, is
comfortably within the range of WBCSD Paris-consistent scenarios. 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% (2023: 2%) is applied from 2028 onwards to determine
the price assumptions in nominal terms (see table below).
The price assumptions used in 2023 were $80.0/bbl (2024), $80.0/bbl (2025),
$75.0/bbl (2026) and $77.0/bbl real thereafter, inflated at 2.0% per annum
from 2027.
2025 2026 2027 2028>(*)
Brent oil ($/bbl) 75.0 75.0 75.0 77.0
(· ) (Inflated at 2% from 2028)
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 18) and, for the
Kraken CGU, 2C resources associated with the Bressay gas well as an
alternative fuel provision for the Kraken FPSO as the basis for calculations
of expected future cash flows from underlying assets because this represents
the reserves and resources 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
Changes in price and its consequential impact on impairment, contingent
consideration and deferred tax along with the discount rate impact on
impairment and decommissioning are considered to be the only key sources of
estimation uncertainty, although other sensitivities that the Group believes
are useful for users of these accounts but are not considered to have a
significant risk of resulting in material changes to carrying amounts in the
next 12 months, may also be provided.
Management tested the impact of a change in cash flows in FVLCD impairment
testing arising from a 10% reduction in crude 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 $221.6 million, which is approximately 10% of the net book
value of property, plant and equipment as at 31 December 2024.
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 10.0% 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 2024
would have been approximately $51.2 million higher. If the discount rate was
one percentage point lower, the net impairment charge would have been
approximately $55.9 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 (2023: $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 10.
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 6(d).
75% Magnus acquisition contingent consideration
Estimates: The Group reassessed the fair value discount rate associated with
the Magnus contingent consideration and estimated it to be 11.3% as at the end
of 2024 (2023: 11.3%), as calculated in line with IFRS 13. Sensitivities and
additional information relating to the 75% Magnus acquisition contingent
consideration are provided in note 21.
Provisions
Estimates: Decommissioning costs will be incurred by the Group at the end of
the operating life of some of the Group's oil and gas production facilities
and pipelines. The Group assesses its decommissioning provision at each
reporting date. The ultimate decommissioning costs are uncertain and cost
estimates can vary in response to many factors, including changes to relevant
legal requirements, estimates of the extent and costs of decommissioning
activities, the emergence of new restoration techniques and experience at
other production sites. The expected timing, extent and amount of expenditure
may also change, for example, in response to changes in oil and gas reserves
or changes in laws and regulations or their interpretation. Therefore,
significant estimates and assumptions are made in determining the provision
for decommissioning. As a result, there could be significant adjustments to
the provisions established which would affect future financial results.
The timing and amount of future expenditures relating to decommissioning and
environmental liabilities are reviewed annually. The 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 2024 was 4.5% (2023:
3.5%), reflecting the UK Gilt interest rate environment. The weighted average
period over which decommissioning costs are generally expected to be incurred
is estimated to be approximately 13 years. Costs at future prices are
determined by applying inflation rates at 2.0% per annum thereafter (2023:
2.5% (2024) and a long-term inflation rate of 2% thereafter) to
decommissioning costs.
Further information about the Group's provisions is provided in note 22.
Changes in assumptions 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 $59.4 million (2023: $68.0
million). The pre-tax impact on the Group income statement would be a charge
of approximately $58.7 million (2023: $67.1 million).
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 2024, 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 2024. 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 is not yet a material part of the Group from a capital and human
resources allocation perspective. 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 2024 North Sea Malaysia All other segments Total segments Adjustments Consolidated
$'000 and
eliminations(i), (iii)
Revenue and other operating income:
Revenue from contracts with customers 1,063,829 123,728 - 1,187,557 - 1,187,557
Other operating income/(expense) 2,709 - 260 2,969 (9,817) (6,848)
Total revenue and other operating income/(expense) 1,066,538 123,728 260 1,190,526 (9,817) 1,180,709
Income/(expenses) line items:
Depreciation and depletion (252,208) (17,042) (41) (269,291) - (269,291)
Net impairment (charge)/reversal to oil and gas assets (71,414) - - (71,414) - (71,414)
Exploration write-off and impairments - (183) - (183) - (183)
Segment profit/(loss)(ii), (iii) 274,354 45,536 9,013 328,903 (17,375) 311,528
Other disclosures:
Capital expenditure(iv) 313,557 32,774 15 346,346 - 346,346
North Sea Malaysia All other segments Total Adjustments Consolidated
segments and
Year ended 31 December 2023 eliminations(i), (iii)
$'000
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), (iii) 330,501 46,192 4,474 381,167 16,206 397,373
Other disclosures:
Capital expenditure(iv) 149,093 11,817 12 160,922 - 160,922
(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) Tax is not included as this is not disclosed to the Chief Operating
Decision Maker within the segment profit/(loss)
(iii) Inter-segment revenues are eliminated on consolidation. All other
adjustments are part of the reconciliations presented further below
(iv)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
2024 2023
$'000 $'000
Segment profit/(loss) before tax and finance income/(costs) 328,903 381,167
Finance costs (159,422) (172,087)
Finance income 14,508 6,493
(Loss)/gain on derivatives(i) (17,375) 16,206
Profit/(loss) before tax 166,614 231,779
(i) Includes $17.6 million realised losses on derivatives (2023: $8.4 million)
and $0.3 million unrealised gains on derivatives (2023: $24.6 million). See
note 18(b) for further detail
Revenue from three 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 $394.8 million, $156.0 million and $115.7 million per
each single customer (2023: two customers; $491.2 million and $201.3 million
per each single customer).
4. 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 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 premium or 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 commodity 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 18).
Year ended 31 December 2024 Year ended 31 December 2023
$'000 $'000
Revenue from contracts with customers:
Revenue from crude oil sales 1,020,266 1,127,419
Revenue from gas and condensate sales(i) 164,647 338,973
Tariff revenue 2,644 1,318
Total revenue from contracts with customers 1,187,557 1,467,710
Realised (losses)/gains on commodity derivative contracts (see note 18) (12,907) (11,264)
Unrealised gains/(losses) on commodity derivative contracts (see note 18) 3,090 28,463
Other 2,969 2,510
Total revenue and other operating income 1,180,709 1,487,419
(i) Includes onward sale of third-party gas purchases not required for
injection activities at Magnus (see note 4(b))
Disaggregation of revenue from contracts with customers
Year ended Year ended
31 December 2024 31 December 2023
$'000 $'000
North Sea Malaysia Total North Sea Malaysia Total
Revenue from contracts with customers:
Revenue from crude oil sales 900,310 119,956 1,020,266 987,610 139,809 1,127,419
Revenue from gas and condensate sales(i) 162,951 1,696 164,647 336,902 2,071 338,973
Tariff revenue 568 2,076 2,644 689 629 1,318
Total revenue from contracts with customers 1,063,829 123,728 1,187,557 1,325,201 142,509 1,467,710
(i) Includes onward sale of third-party gas purchases not required for
injection activities at Magnus (see note 4(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 2024 Year ended 31 December 2023
$'000 $'000
Production costs 307,634 308,331
Tariff and transportation expenses 70,449 41,736
Realised loss/(gain) on derivative contracts related to operating costs (see 4,735 (2,839)
note 18)
Unrealised losses/(gains) on derivative contracts related to operating costs 2,823 3,832
(see note 18)
Change in lifting position 3,528 (2,669)
Crude oil inventory movement (1,356) (1,575)
Depletion of oil and gas assets(i) 263,251 292,199
Movement in contractor dispute provision - 1,818
Other cost of operations(ii) 136,319 305,919
Total cost of sales 787,383 946,752
(i) Includes $27.9 million (2023: $28.6 million) Kraken FPSO right-of-use
asset depreciation charge and $23.5 million (2023: $24.0 million) of other
right-of-use assets depreciation charge
(ii) Includes $125.7 million (2023: $294.0 million) of purchases and
associated costs of third-party gas not required for injection activities at
Magnus, which is sold on
(c) General and administration expenses
Year ended 31 December 2024 Year ended 31 December 2023
$'000 $'000
Staff costs (see note 4(e)) 75,833 77,517
Depreciation(i) 6,040 6,109
Other general and administration costs 26,748 25,490
Recharge of costs to operations and joint venture partners (102,919) (102,768)
Total general and administration expenses 5,702 6,348
(i) Includes $3.4 million (2023: $3.4 million) right-of-use assets
depreciation charge on buildings
(d) Other (expenses)/income
Year ended 31 December 2024 Year ended 31 December 2023
$'000 $'000
Net foreign exchange gains/(losses) 9,975 (11,659)
Rental income from office sublease 2,201 2,286
Fair value changes in contingent consideration (see note 21) ((i)) (15,904) 10,811
Change in decommissioning provisions (see note 22) (6,666) (31,159)
Change in Thistle decommissioning provision (see note 22) (412) (1,605)
Drilling rig contract cancellation costs((ii)) (14,629) -
Unsuccessful exploration expenditure (see note 11) (183) (5,640)
Insurance income 1,663 4,127
Reversal of provisions - 101
Other 19,273 13,188
Total other (expenses)/income (4,682) (19,550)
(i) In previous periods, the element of the movement in the fair value of the
Magnus contingent consideration due to the passage of time ("unwinding of
discount") has been recorded within finance costs, with remaining fair value
movements recorded within other income or expense. Following a review of this
presentation and comparing this to market practice, it has been concluded that
it would be more appropriate for the impact from both the unwind of discount
and other changes in fair value to be combined within other income/expense,
with comparative information restated. This restatement results in a $58.9
million charge for 2023 being reclassified from finance costs to other
income/expense, with no impact on net income or closing retained earnings for
that year
(ii) Drilling rig contract at Kraken was terminated due to a deferral of
infill drilling
(e) 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 2024 Year ended 31 December 2023
$'000 $'000
Wages and salaries 66,700 63,458
Social security costs 5,899 5,457
Defined contribution pension costs 5,265 5,038
Expense of share-based payments (see note 20) 983 3,320
Other staff costs 12,300 11,079
Total employee costs 91,147 88,352
Contractor costs 37,493 38,304
Total staff costs 128,640 126,656
General and administration staff costs (see note 4(c)) 75,833 77,517
Non-general and administration costs 52,807 49,139
Total staff costs 128,640 126,656
The monthly average number of persons, excluding contractors, employed by the
Group during the year was 673, with 336 in the general and administration
staff costs and 337 directly attributable to assets (2023: 697 of which 343 in
general and administration and 354 directly attributable to assets).
Compensation of key management personnel is disclosed in note 26.
(f) Auditor's remuneration
The following amounts for the year ended 31 December 2024 and for the
comparative year ended 31 December 2023 were payable by the Group to Deloitte:
Year ended 31 December 2024 Year ended 31 December 2023
$'000 $'000
Fees payable to the Company's auditor for the audit of the parent company and 1,367 1,239
Group financial statements
The audit of the Company's subsidiaries 173 149
Total audit 1,540 1,388
Audit-related assurance services(i) 589 314
Total audit and audit-related assurance services 2,129 1,702
Total auditor's remuneration 2,129 1,702
(i) Audit-related assurance services in both years include the review of the
Group's interim results, G&A assurance review and the provision of
customary comfort letters in respect of the debt refinancing
5. 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 2024 Year ended 31 December 2023
$'000 $'000
Finance costs:
Loan interest payable 18,524 30,708
Bond interest payable 54,971 58,999
Unwinding of discount on decommissioning provisions (see note 22) 30,290 24,236
Unwinding of discount on other provisions (see note 22) 911 1,145
Debt refinancing fees (see note 17) 4,809 -
Finance charges payable under leases (see note 23) 27,673 43,801
Finance fees on loans and bonds including amortisation of capitalised fees 14,473 7,899
Other financial expenses(i) 7,771 5,299
Total finance costs 159,422 172,087
Finance income:
Bank interest receivable 11,110 6,493
RockRose loan interest (see note 18(f)) 3,263 -
Other financial income 135 -
Total finance income 14,508 6,493
(i) 2023 includes unwinding of discount on Golden Eagle contingent
consideration of $1.7 million. See note 21
6. 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.
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 the Group intends 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. 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 2024 Year ended 31 December 2023
$'000 $'000
Current UK income tax
Current income tax charge - -
Adjustments in respect of current income tax of previous years - (14)
Current overseas income tax
Current income tax charge 11,432 24,685
Adjustments in respect of current income tax of previous years (746) (2,567)
UK Energy Profits Levy
Current year charge 10,262 175,118
Adjustments in respect of current charge of previous years (8,803) (11,605)
Total current income tax 12,145 185,617
Deferred UK income tax
Relating to origination and reversal of temporary differences 42,745 160,712
Adjustments in respect of deferred income tax of previous years (9,103) 4,974
Deferred overseas income tax
Relating to origination and reversal of temporary differences 7,071 (3,761)
Adjustments in respect of deferred income tax of previous years 31 1,430
Deferred UK Energy Profits Levy
Relating to origination and reversal of temporary differences 11,156 (58,661)
Adjustments in respect of changes in tax rates 6,889 -
Adjustments in respect of deferred charge of previous years 1,907 (27,699)
Total deferred income tax 60,696 76,995
Income tax expense reported in profit or loss 72,841 262,612
(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
2024 2023
$'000 $'000
Profit/(loss) before tax 166,614 231,779
UK statutory tax rate applying to North Sea oil and gas activities of 40% 66,646 92,712
(2023: 40%)
Supplementary corporation tax non-deductible expenditure 5,809 10,580
Non-deductible expenditure(i) 26,114 69,494
Non-taxable gain on sale of assets 505 -
Petroleum revenue tax (net of income tax benefit) (8,938) (8,200)
Tax in respect of non-ring-fence trade 7,298 7,418
Deferred tax asset not recognised in respect of non-ring-fence trade 12,243 11,696
Deferred tax asset recognised on previously unrecognised losses (48,115) -
UK Energy Profits Levy(ii) (13,921) 116,457
UK Energy Profits Levy - changes in tax rates(ii) 6,889 -
UK Energy Profits Levy - abolishment of Investment Allowance(ii) 35,339 -
Adjustments in respect of prior years (16,713) (35,481)
Overseas tax rate differences 2,045 (1,114)
Share-based payments (1,407) (90)
Other differences (953) (860)
At the effective income tax rate of 44% (2023: 113%) 72,841 262,612
(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) Total current year EPL charge only. This consists of an EPL current tax
charge of $10.3 million (2023: $175.1 million charge) and deferred EPL charge
of $18.0 million (2023: $58.7 million credit). The impact of the substantially
enacted Autumn Statement changes referred to in part (e) below are included
within these amounts and have been disclosed separately above
(c) Deferred income tax
Deferred income tax relates to the following:
Group balance sheet Charge/(credit) for the year recognised in profit or loss
2024 2023 2024 2023
$'000 $'000 $'000 $'000
Deferred tax liability
Accelerated capital allowances 911,501 877,800 33,701 (86,015)
911,501 877,800
Deferred tax asset
Losses (717,900) (695,888) (22,012) 206,213
Decommissioning liability (263,705) (265,800) 2,095 (27,176)
Other temporary differences((i)) (331,679) (378,591) 46,912 (16,027)
(1,313,284) (1,340,279) 60,696 76,995
Net deferred tax (assets)((ii)) (401,783) (462,479)
Reflected in the balance sheet as follows:
Deferred tax assets (506,481) (540,122)
Deferred tax liabilities 104,698 77,643
Net deferred tax (assets) (401,783) (462,479)
(i) Predominantly includes $199.2 million related to Magnus acquisition
contingent consideration in note 21 and $107.7 million on deferred income in
note 24
(ii)The total amounts for EPL included in net deferred assets are $160.7
million for accelerated capital allowances and $73.4 million for other items,
which predominantly includes $18.7 million Magnus acquisition contingent
consideration (note 21) and $52.5 million deferred income (note 24)
Reconciliation of net deferred tax assets/(liabilities)
2024 2023
$'000 $'000
At 1 January 462,479 539,474
Tax expense during the period recognised in profit or loss (60,696) (76,995)
At 31 December 401,783 462,479
(d) Tax losses
The Group's deferred tax assets at 31 December 2024 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 $62.1 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 $496.1 million
(2023: $442.1 million) and ring-fence tax losses of $1,117.5 million (2023:
$1,163.0 million) associated with the Bentley acquisition, for which no
deferred tax asset has been recognised at the balance sheet date as of
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 $6.3 million (2023: $8.5 million) remaining unrecognised.
The Group has unused Malaysian income tax losses of $14.7 million (2023: $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
In June 2023, the UK 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 exposure to Pillar Two income taxes
from 1 January 2024 and it does not have an 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.
In the Autumn Statement on 22 November 2023, the UK Government confirmed that
it will bring in legislation for the Energy Security Investment Mechanism
('ESIM') which would remove the EPL if both average oil and gas prices fall
to, or below, $71.40 per barrel for oil and £0.54 per therm for gas, for two
consecutive quarters, and agreed to index link the trigger floor price to the
CPI from April 2024. From April 2024, the ESIM threshold prices were revised
to $74.21 per barrel for oil and £0.57 per therm for gas. EnQuest does not
currently forecast that the floor price will be met for both oil and gas
prices and therefore there is currently no impact from this on tax carrying
values.
In the Autumn Statement on 30 October 2024, the UK Government confirmed that
from 1 November 2024 the rate of Energy Profits Levy ('EPL') would be
increased from 35% to 38%. They also announced that the EPL Investment
Allowance would be abolished from 1 November 2024 (although First Year
Allowances would be retained) and decarbonisation relief would be reduced from
80% to 66%. The impact of these changes on the current year financial
statements is an increase in the tax charge and deferred tax for EPL of $42.2
million. The announcement to extend the EPL period to 31 March 2030 was not
substantively enacted at 31 December 2024 and therefore is not included in the
tax balances included in these financial statements. It is expected that this
extension, which was substantively enacted on 3 March 2025, will result in the
recognition of an additional deferred tax liability of approximately $115.9
million.
7. Earnings per share
The calculation of basic 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.
During the year to 31 December 2024, the Group repurchased 55,894,836 Ordinary
shares, of which 25,000,000 ordinary shares have been classified in the
balance sheet as Treasury shares with the balance cancelled (see note 8). The
Treasury shares have been excluded for the purposes of calculating the basic
and diluted earnings per share at 31 December 2024.
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
2024 2023 2024 2023 2024 2023
$'000 $'000 million million $ $
Basic 93,773 (30,833) 1,891.9 1,871.9 0.050 (0.016)
Dilutive potential of Ordinary shares granted under share-based incentive - - 24.3 32.4 (0.001) -
schemes
Diluted(i) 93,773 (30,833) 1,916.2 1,904.3 0.049 (0.016)
(i) Potential Ordinary shares are not treated as dilutive when they would
decrease a loss per share and as a result the weighted average number of
Ordinary shares used as the denominator in the calculation of diluted EPS is
the same as that used for calculating basic EPS in 2023.
8. Distributions paid and proposed
The Company paid no dividends during the year ended 31 December 2024 (2023:
none). At 31 December 2024, there were no proposed dividends (2023: none).
During 2024, a share buyback programme was executed with a total of 55,894,836
shares ($9.0 million) repurchased as at 31 December 2024.
Having continued to reduce EnQuest net debt and optimise the debt structure,
EnQuest is now positioned to balance deploying capital for growth and returns
to shareholders. As such, the Board is pleased to propose a final ordinary
dividend of 0.616 pence per share (equivalent to c.$15 million). This final
dividend is subject to approval by shareholders at the Annual General Meeting
on 27 May 2025 and so not recognised as a liability as at 31 December 2024. If
approved, the dividend will be paid on 6 June 2025 to shareholders on the
register at 2 May 2025. Shares will trade ex-dividend from 1 May 2025.
9. 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. Any
changes in estimate are accounted for on a prospective basis.
Impairment of tangible (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 (or CGU) is estimated to be less than its
carrying amount, the carrying amount of the asset (or CGU) 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 (or CGU) 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 (or CGU) 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 23)
$'000
Cost:
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 53,333 - - 53,333
Disposal - - (243) (243)
Reclassification from intangible assets (note 11) 31,803 - - 31,803
At 1 January 2024 9,243,807 68,578 904,994 10,217,379
Additions 325,813 394 16,453 342,660
Change in decommissioning provision (note 22) (741) - - (741)
At 31 December 2024 9,568,879 68,972 921,447 10,559,298
Accumulated depreciation, depletion and impairment:
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 1 January 2024 7,364,063 59,314 497,262 7,920,639
Charge for the year 211,873 2,683 54,735 269,291
Net impairment charge/(reversal) for the year 75,428 - (4,014) 71,414
At 31 December 2024 7,651,364 61,997 547,983 8,261,344
Net carrying amount:
At 31 December 2024 1,917,515 6,975 373,464 2,297,954
At 31 December 2023 1,879,744 9,264 407,732 2,296,740
At 1 January 2023 2,036,901 10,696 429,378 2,476,975
The amount of borrowing costs capitalised during the year ended 31 December
2024 was nil (2023: 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
(charge)/reversal amount(i)
Year ended 31 December 2024 Year ended 31 December 2023
$'000 $'000 31 December 2024 31 December 2023
$'000 $'000
North Sea (71,414) (117,396) 1,172,487 1,323,009
Net pre-tax impairment (charge)/reversal (71,414) (117,396)
(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 2024 net impairment charge of $71.4 million relates to producing assets in
the UK North Sea (charges of $2.0 million for GKA and Scolty/Crathes CGU,
$62.5 million for Golden Eagle and $20.1 million for Alba offset by an
impairment reversal of $13.2 million at Kraken). Impairment charges/reversals
were primarily driven by EPL revisions, lower near-term oil price assumptions
and changes in production profiles, partially offset by a lower discount rate.
The 2023 net impairment charge of $117.4 million related to producing assets
in the UK North Sea (charges of $17.2 million for GKA and Scolty/Crathes CGU,
$122.5 million for Golden Eagle and $9.1 million for Alba offset by an
impairment reversal of $31.4 million at Kraken). Impairment charges/reversals
were primarily driven by changes in production and cost profile updates,
partially offset by higher forecast oil prices.
10. 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 (or group of CGUs) to
which the goodwill relates should be assessed.
For the purposes of impairment testing, goodwill acquired is allocated to the
CGU (or group of CGUs) 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 (or groups of CGUs) to which the goodwill relates. Where the
recoverable amount of the CGU (or groups of CGUs) is less than the carrying
amount of the CGU (or group of CGUs) 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:
2024 2023
$'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 grouping of CGUs, 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 9).
The recoverable amounts of the segment and fields have been determined on a
fair value less costs of disposal basis. See notes 2 and 9 for further
details. An impairment charge of nil was taken in 2024 (2023: nil) based on a
fair value less costs to dispose valuation of the North Sea segment grouping
of CGUs, 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 result in an impairment charge of $66.7 million
(2023: 10% reduction would not result in an impairment charge). A 17%
reduction in oil price would fully impair goodwill (2023: 20%), however
Management do not consider this to be a reasonable expectation.
11. 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 2024, there was no impairment of historical
exploration and appraisal expenditures (2023: nil). During 2023, $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. Also 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 were
written off through the income statement during 2023 with an additional $0.2
million written off during 2024.
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 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 9) (31,803) - (31,803)
Disposal - (1,199) (1,199)
At 1 January 2024 127,476 876 128,352
Additions 3,686 1,138 4,824
Write-off of unsuccessful exploration expenditure (183) - (183)
Disposal (1,263) (876) (2,139)
At 31 December 2024 129,716 1,138 130,854
Accumulated impairment:
At 1 January 2023 (109,638) - (109,638)
Write-off of relinquished licences previously impaired 485 - 485
At 1 January 2024 and 31 December 2024 (109,153) - (109,153)
Net carrying amount:
At 31 December 2024 20,563 1,138 21,701
At 31 December 2023 18,323 876 19,199
At 1 January 2023 45,299 1,199 46,498
12. 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.
2024 2023
$'000 $'000
Hydrocarbon inventories 22,544 21,189
Well supplies 26,432 63,608
48,976 84,797
During 2024, a net gain of $6.9 million was recognised within cost of sales in
the Group income statement relating to inventory (2023: net gain of $2.2
million). During the current year, following a review of the balance of well
supplies held within inventory, it was concluded that some items met the
definition of property, plant & equipment, and were reclassified during
the current year end and presented as PP&E additions within PP&E (note
9).
The inventory valuation at 31 December 2024 is stated net of a provision of
$28.5 million (2023: $36.3 million) to write-down well supplies to their
estimated net realisable value.
13. Cash and cash equivalents
Accounting policy
Cash and cash equivalents includes cash at bank, cash in hand, cash deposited
in relation to decommissioning security arrangements and highly liquid
interest-bearing securities with original maturities of three months or fewer.
2024 2023
$'000 $'000
Available cash 226,317 313,028
Restricted cash 53,922 544
Cash and cash equivalents 280,239 313,572
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
During 2024, additional security was required to be provided in accordance
with the Group's decommissioning security arrangements. EnQuest renewed its
surety bond facilities and added three new providers, with $53.4 million of
cash required to be placed on deposit (31 December 2023: nil). The remaining
$0.5 million of restricted cash relates to bank guarantees for the Group's
Malaysian assets (31 December 2023: $0.5 million).
14. 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 in 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 27. The Group also enters
into forward contracts for the purchase of UKAs to manage its exposure to
carbon emission credit prices. 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.
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 21) and a listed
equity investment (see note 18). The movements of both are recognised within
the Group income statement.
Fair value measurement
The following table provides the fair values and fair value measurement
hierarchy of the Group's other financial assets and liabilities:
31 December 2024 Notes Carrying Value Quoted prices in active markets (Level 1) $'000 Significant observable inputs Significant unobservable inputs
$'000 (Level 2) (Level 3)
$'000 $'000
Total
$'000
Financial assets measured at fair value:
Derivative financial assets measured at FVPL
Gas commodity contracts 18(a) 69 69 - 69 -
Other financial assets measured at FVPL -
Quoted equity shares 6 6 6 - -
Total financial assets measured at fair value 75 75 6 69 -
Financial assets measured at amortised cost:
Vendor financing facility 18(f) 38,453 38,453 - 38,453 -
Total financial assets measured at amortised cost((i)) 38,453 38,453 - 38,453 -
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Commodity derivative contracts 18(a) 10,497 10,497 - 10,497 -
Forward foreign currency contracts 18(a) 2,354 2,354 - 2,354 -
Forward UKA contracts 18(a) 8,729 8,729 - 8,729 -
Other financial liabilities measured at FVPL
Contingent consideration 21 473,294 473,294 - - 473,294
Total liabilities measured at fair value 494,874 494,874 - 21,580 473,294
Liabilities measured at amortised cost
Interest-bearing loans and borrowings((i)) 17 33,972 33,972 - 33,972 -
Retail bond 9.00%((ii)) 17 169,371 161,461 161,461 - -
High yield bond 11.625%((ii)) 17 461,514 466,102 466,102 - -
Total liabilities measured at amortised cost((iii)) 664,857 661,535 627,563 33,972 -
((i)) Amortised cost is a reasonable approximation of the fair value
((ii)) Carrying value includes accrued interest
((iii)) Excludes related fees
31 December 2023 Notes Carrying Value Quoted prices in active markets (Level 1) Significant observable inputs Significant unobservable inputs
$'000 $'000 (Level 2) (Level 3)
$'000 $'000
Total
$'000
Financial assets measured at fair value:
Derivative financial assets measured at FVPL
Gas commodity contracts 18(a) 4,499 4,499 - 4,499 -
Other financial assets measured at FVPL
Quoted equity shares 6 6 6 - -
Total financial assets measured at fair value 4,505 4,505 6 4,499 -
Financial assets measured at amortised cost:
Vendor financing facility 18(f) 145,103 145,103 - 145,103 -
Total financial assets measured at amortised cost((i)) 145,103 145,103 - 145,103 -
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Oil commodity derivative contracts 18(a) 18,418 18,418 - 18,418 -
Forward UKA contracts 18(a) 8,261 8,261 - 8,261 -
Other financial liabilities measured at FVPL
Contingent consideration 21 507,796 507,796 - - 507,796
Total liabilities measured at fair value 534,475 534,475 - 26,679 507,796
Liabilities measured at amortised cost
Interest-bearing loans and borrowings((i)) 17 319,784 319,784 - 319,784 -
Retail bond 9.00% 17 169,669 158,683 158,683 - -
High yield bond 11.625% 17 294,276 292,419 292,419 - -
Total liabilities measured at amortised cost((ii)) 783,729 770,886 451,102 319,784 -
((i)) Amortised cost is a reasonable approximation of the fair value
((ii)) Excludes related fees
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 21. There have been no transfers between Level 1 and Level 2
during the period (2023: 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 29.
15. Trade and other receivables
2024 2023
$'000 $'000
Current
Trade receivables 20,151 31,905
Joint venture receivables 106,963 79,036
Under-lift position 16,806 22,309
VAT receivable 7,574 3,314
Other receivables 4,729 3,715
Prepayments 7,822 2,781
Accrued income 66,926 82,426
Total current 230,971 225,486
Non-current
Other receivables 2,102 -
Total non-current 2,102 -
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 4(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 2024 or 2023.
Non-current trade and other receivables represents capitalised fees associated
with the Group's Reserve Based Lending Facility that were reclassed to trade
and other receivables to better reflect the variable nature of the facility
following the repayment in full of the outstanding principal ($140.0 million)
in February 2024.
16. Trade and other payables
2024 2023
$'000 $'000
Current
Trade payables 138,822 75,981
Accrued expenses 209,225 228,664
Over-lift position 16,849 18,824
Joint venture creditors 46,187 20,262
Other payables 3,307 3,678
Total Current 414,390 347,409
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 2023 non-current trade and other payables as
stated above was considered to be a reasonable approximation to their fair
value as this represented a specific bi-lateral agreement between
counterparties with the liability extinguished in full over time in accordance
with the agreed schedule. The outstanding amount at 31 December 2024 is now
presented within current trade and other payables.
17. Loans and borrowings
2024 2023
$'000 $'000
Loans 33,972 311,231
Bonds 630,885 463,945
664,857 775,176
The Group's borrowings are carried at amortised cost as follows:
2024 2023
Principal $'000 Fees Total Principal Fees Total
$'000
$'000 $'000 $'000 $'000
RBL facility((i)) - - - 140,000 (4,920) 135,080
Term loan facility - - - 150,000 (3,633) 146,367
SVT working capital facility 33,972 - 33,972 29,784 - 29,784
High yield bond 11.625% 465,000 (10,661) 454,339 305,000 (10,724) 294,276
Retail bond 9.00% 167,101 - 167,101 169,669 - 169,669
Accrued interest((ii)) 9,445 - 9,445 - - -
Total borrowings 675,518 (10,661) 664,857 794,453 (19,277) 775,176
Due within one year 43,417 27,364
Due after more than one year 621,440 747,812
Total borrowings 664,857 775,176
((i)) Capitalised fees were reclassed in the current period to trade and other
receivables to better reflect the variable nature of the facility
((ii)) Accrued interest on borrowings has been reclassed in the current period
to better reflect the total borrowings balance (comparative information has
not been restated as it is not material). Accrued interest includes bond
interest accruals of $9.4 million
See liquidity risk - note 27 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 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% until July 2025
when it increases to 4.50%, plus a combination of an agreed credit adjustment
spread and the Secured Overnight Financing Rate ('SOFR'). The Group fully
repaid the $140.0 million of its drawn Reserve Based Lending Facility in
February 2024. At 31 December 2024, $176.4 million remained available for
drawdown under the RBL (2023: $166.2 million). Effective from 1 January 2025,
the amount available to drawdown increased to $237.1 million as a result of
the annual redetermination process.
At 31 December 2024, the Letter of Credit utilisation was $54.1 million (2023:
$43.5 million).
Term loan facility
In August 2023, the Group agreed a second lien US Dollar term loan facility of
$150.0 million which was drawn down in full in September 2023 and incurred
interest at SOFR +7.90%. In October 2024, the term loan, plus the early
redemption fee of $4.7 million, was fully repaid utilising the proceeds from
the high yield bond tap. The early redemption fee and the remaining
unamortised costs of $2.9 million were expensed within finance costs.
SVT working capital facility
EnQuest has extended the £42.0 million revolving loan facility with a joint
operations partner to fund the short-term working capital cash requirements of
SVT and associated interests until April 2027. The facility is guaranteed by
BP EOC Limited (joint operations partner) 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 2.05% per annum plus GBP Sterling Over Night Index
Average ('SONIA').
Vendor Loan facility
In August 2024, the Group entered into a deferred payment facility agreement
with a third-party vendor providing capacity for refinancing the payment of
existing invoices up to an amount of £23.7 million, with interest payable
monthly at a rate of 9.50% per annum. At 31 December 2024, nil was drawn down
on the facility, with $20.7 million drawn by the end of February 2025.
High yield bond 11.625%
In October 2022, the Group concluded an offer of $305.0 million for a US
Dollar high yield bond. In October 2024, the Group concluded a tap of an
additional $160.0 million of the US Dollar high yield bond on the same terms
and conditions as the existing bond. The notes accrue a fixed coupon of
11.625% payable semi-annually in arrears with a maturity date of November
2027. Associated fees of $3.4 million were capitalised and are being amortised
over the period of the bond.
The above carrying value of the bond as at 31 December 2024 is $454.3 million
(2023: $294.3 million). This includes bond principal of $465.0 million (2023:
$305.0 million) and unamortised issue premium on the tap of $1.4 million less
the unamortised original issue discount of $2.4 million (2023: $3.3 million)
and unamortised fees of $9.7 million (2023: $7.4 million). The fair value of
the high yield bond is disclosed in note 14.
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 2024 is $167.1 million
(2023: $169.7 million). All fees associated with this offer were recognised in
the income statement in 2022. The fair value of the retail bond 9.00% is
disclosed in note 14.
18. Other financial assets and financial liabilities
(a) Summary as at year end
2024 2023
Assets Liabilities $'000 Assets Liabilities $'000
$'000
$'000
Fair value through profit or loss:
Derivative commodity contracts 69 10,497 4,499 18,418
Forward foreign currency contracts - 2,354 - -
Derivative UKA contracts - 8,729 - 8,261
Amortised cost:
Other receivables (Vendor financing facility) (notes 18(f), 24) - - 108,827 -
Total current 69 21,580 113,326 26,679
Fair value through profit or loss:
Quoted equity shares 6 - 6 -
Amortised cost:
Other receivables (Vendor financing facility) (notes 18(f), 24) 38,453 - 36,276 -
Total non-current 38,459 - 36,282 -
Total other financial assets and liabilities 38,528 21,580 149,608 26,679
(b) Income statement impact
The income/(expense) recognised for derivatives are as follows:
Year ended 31 December 2024 Revenue and other operating income Cost of
sales
Realised $'000 Unrealised $'000 Realised $'000 Unrealised $'000
Commodity options (19,899) 10,617 - -
Commodity swaps 7,467 (7,340) - -
Commodity futures (475) (187) - -
Foreign exchange contracts - - 2,859 (2,354)
UKA contracts - - (7,594) (469)
(12,907) 3,090 (4,735) (2,823)
Year ended 31 December 2023 Revenue and other operating income Cost of
sales
Realised Unrealised $'000 Realised Unrealised $'000
$'000 $'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)
(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 2024, losses totalling $9.8 million (2023:
gains of $17.2 million) were recognised in respect of commodity contracts
measured as FVPL. This included losses totalling $12.9 million (2023: losses
of $11.3 million) realised on contracts that matured during the year, and
mark-to-market unrealised gains totalling $3.1 million (2023: gains of $28.5
million).
The mark-to-market value of the Group's open commodity contracts as at 31
December 2024 was a net liability of $10.4 million (2023: net liability of
$13.9 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 2024, gains totalling
$0.5 million (2023: gains of $5.7 million) were recognised in the Group income
statement. This included realised gains totalling $2.9 million (2023: gains of
$5.7 million) on contracts that matured in the year.
The mark-to-market value of the Group's open contracts as at 31 December 2024
was a net liability of $2.4 million (2023: 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. During the year ended 31 December
2024, losses totalling $8.1 million (2023: losses of $6.7 million) were
recognised in the Group income statement. This included realised losses
totalling $7.6 million (2023: losses of $2.9 million) on contracts that
matured in the year.
The mark-to-market value of the Group's open contracts as at 31 December 2024
was a net liability of $8.7 million (2023: $8.3 million).
(f) Other receivables
Other receivables
$'000 Equity shares Total
$'000 $'000
At 1 January 2023 - 6 6
Additions((i)) 145,103 - 145,103
At 31 December 2023 145,103 6 145,109
Interest 3,263 - 3,263
Repayments (107,518) - (107,518)
Foreign Exchange (2,395) - (2,395)
At 31 December 2024 38,453 6 38,459
Current -
Non-current 38,459
38,459
((i))Additions in 2023 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. $107.5 million was repaid in the first quarter of 2024
with the remainder 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.
19. Share capital and reserves
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.
Treasury shares
Represents amounts transferred following purchase of the Company's own shares
out of distributable profits, with those shares available for resale into the
market, transfer to the Group's Employee Benefit Trust ('EBT') where they can
be used to satisfy awards made under the Company's share-based incentive
schemes, or cancelled.
Capital redemption reserve
Represents the par value of shares cancelled following the purchase of the
Company's own shares out of distributable profits.
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 EBT are recognised at
cost and are deducted from the share-based payments reserve, as they are held
to satisfy awards made under equity-settled share-based payment transactions.
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 Treasury shares Capital redemption reserve Total
Number $'000 $'000 $'000 $'000
At 1 January 2024 1,912,304,113 133,285 260,546 - - 393,831
Issue of new shares to EBT 3,620,226 229 - - - 229
Repurchase and cancellation of shares (30,894,836) (2,006) - (4,425) 2,006 (4,425)
At 31 December 2024 1,885,029,503 131,508 260,546 (4,425) 2,006 389,635
During 2024, a share buyback programme was executed with a total of 55,894,836
Ordinary shares repurchased as at 31 December 2024. The first 25,000,000
Ordinary shares purchased under the Programme are held in Treasury for issue
in due course to the Company's EBT to satisfy the anticipated future exercise
of options and awards made to employees and Executive Directors of EnQuest PLC
pursuant to certain of the Company's existing share plans. The remaining
30,894,836 Ordinary shares were cancelled.
At 31 December 2024, there were 972,269 shares held by the EBT (2023:
8,449,793) which are included within the share-based payment reserve. The
movement in the year was 11,097,750 shares used to satisfy awards made under
the Company's share-based incentive schemes offset by a subscription for
3,620,226 additional Ordinary shares.
At 1 January 2023, the number of Ordinary shares was 1,885,924,339. In
December 2023, 26,379,774 shares were issued and subsequently transferred to
the EBT.
20. 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.
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:
2024 2023
$'000 $'000
Performance Share Plan 511 2,120
Other performance share plans 64 231
Sharesave Plan 408 969
983 3,320
The following table shows the number of shares potentially issuable under the
Group's various 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 2024 2023
Number Number
Outstanding at 1 January 87,367,455 102,271,264
Granted during the year 35,353,664 33,940,859
Exercised during the year (7,291,023) (19,459,260)
Forfeited during the year (26,812,413) (29,385,408)
Outstanding at 31 December 88,617,683 87,367,455
Exercisable at 31 December 9,138,271 17,944,371
Within the Group's equity-settled employee share plans detailed above, 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.
Sharesave options 2024 2023
Number Weighted average exercise price $ Number Weighted average exercise price
$
Outstanding at 1 January 18,658,144 0.16 33,308,249 0.14
Granted during the year - - 10,268,853 0.14
Exercised during the year (5,478,693) 0.13 (19,977,354) 0.13
Forfeited during the year (3,223,434) 0.15 (4,941,604) 0.17
Outstanding at 31 December 9,956,017 0.15 18,658,144 0.16
Exercisable at 31 December 323,886 0.24 6,553,159 0.13
21. 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 as part of the overall fair value change within other
(expenses)/income.
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.
Settlement of contingent consideration recorded at fair value through profit
or loss is recorded as investing outflows in the cash flow statement to the
extent cumulative amounts paid do not exceed the amount recognised at the date
of acquisition, with any excess recorded as an operating cash outflow.
Settlement of contingent consideration relating to an asset acquisition is
recorded as an investing cash outflow.
Magnus 75% Magnus decommissioning-linked liability Total
$'000 $'000 $'000
At 31 December 2023 488,007 19,789 507,796
Unwinding of discount (see note 4(d)) 55,144 2,301 57,445
Other changes in fair value (see note 4(d)) (43,353) 1,812 (41,541)
Utilisation (48,465) (1,941) (50,406)
At 31 December 2024 451,333 21,961 473,294
Classified as:
Current 18,905 1,498 20,403
Non-current 432,428 20,463 452,891
451,333 21,961 473,294
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 2024, which resulted in a
decrease in fair value (excluding the impact of unwind of discount) of $43.4
million (2023: decrease of $69.8 million). Thi decrease in 2024 reflects a
reduction in the Group's near-term oil price assumptions and changes in the
assets cost and production profile. The decrease in 2023 reflected 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 overall fair value accounting effect including the unwinding of discount,
totalling a charge of $11.8million (2023: credit of $13.2 million) on the
contingent consideration were recognised in the Group income statement. At 31
December 2024, the contingent profit-sharing arrangement cap of $1.0 billion
was forecast to be met in the present value calculations (31 December 2023:
cap was forecast to be met). Within the statement of cash flows, the profit
share element of the repayment, $48.5 million (2023: $65.5 million), is
disclosed separately under investing activities. At 31 December 2024, the
contingent consideration for Magnus was $451.3 million (31 December 2023:
$488.0 million).
Management has considered alternative scenarios to assess the valuation of the
contingent consideration including, but not limited to, the key accounting
estimates relating to the oil price, discount rate and their interrelationship
with production and the profit-share arrangement. As described within note 2,
oil price has been assessed by Management as the only key source of estimation
uncertainty due to its material impact on revenue, which in turn results in
changes in the contingent consideration present value calculations due to the
timing of future cashflows and production profiles. 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 oil price
assumptions of 10%, which is considered to be a reasonably possible change.
This results in a reduction of $51.1 million to the contingent consideration
(2023: reduction of $83.3 million). 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
$19.8 million. A 1.0% increase would decrease reported contingent
consideration by $18.6 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 2024, the maturity
analysis of the contingent consideration is disclosed in Risk management and
financial instruments: liquidity risk (note 27).
Magnus decommissioning-linked contingent consideration
As part of the Magnus and associated interests acquisition, bp retained the
decommissioning liability in respect of the existing wells and infrastructure
and EnQuest agreed to pay additional consideration in relation to the
management of the physical decommissioning costs of Magnus. At 31 December
2024, the amount due to bp calculated on an after-tax basis by reference to
30% of bp's decommissioning costs on Magnus was $22.0 million (2023: $19.8
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. The balance at 31
December 2024 was nil (31 December 2023: nil).
22. 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 2023 755,762 25,355 14,180 795,297
Additions during the year(i) 2,893 - 835 3,728
Changes in estimates(i) 3,032 412 - 3,444
Unwinding of discount 30,290 911 - 31,201
Utilisation (50,412) (8,319) (9,063) (67,794)
Foreign exchange - (11) 241 230
At 31 December 2024 741,565 18,348 6,193 766,106
Classified as:
Current 42,030 7,700 5,400 55,130
Non-current 699,535 10,648 793 710,976
741,565 18,348 6,193 766,106
(i) Includes $6.7 million relating to assets in decommissioning disclosed in
note 4(d) and $(0.7) million related to producing assets disclosed in note 9
Decommissioning provision
The Group's total provision represents the present value of decommissioning
costs which are expected to be incurred up to 2050, 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
Golden Eagle. Changes in estimates during the year primarily reflect the net
effect of $78.0 million increase in the underlying cost estimates partly
offset by $59.0 million impact from the increase in the discount rate and
$12.4 million foreign exchange impact due to the weakening of Sterling to US
Dollar exchange rates. At 31 December 2024, an estimated $281.1 million is
expected to be utilised between one and five years (2023: $175.7 million),
$280.0 million within six to ten years (2023: $355.6 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 (see note 13). The surety bond facilities, which
expired in December 2023, were renewed for 12 months, subject to ongoing
compliance with the terms of the Group's borrowings. At 31 December 2024, the
Group held surety bonds totalling $277.0 million (2023: $250.4 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 2024, the amount
due to bp by reference to 7.5% of bp's decommissioning costs on Thistle and
Deveron was $18.3 million (2023: $25.4 million), with the reduction mainly
reflecting the utilisation in the period. Change in estimates of $0.4 million
are included within other expense (2023: $1.6 million) and unwinding of
discount of $0.9 million is included within finance costs (2023: $1.1
million).
Other provisions
At 31 December 2023, the provision included a dispute with a third-party
contractor of $9.1 million including legal costs and interest charges. In
August 2024, the Malaysian Court of Appeal issued a judgement that funds held
in escrow, should be released to the third party supplier pending resolution
of the final arbitration decision. As such $8.6 million was released from
escrow and hence deducted from the provision. Should the final arbitration
decision find in the favour of EnQuest, EnQuest would seek reimbursement of
any funds transferred. The Group expects the dispute to be settled in 2025.
23. 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 9).
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 2022 429,378 482,066
Additions in the period 28,378 28,378
Depreciation expense (55,979) -
Impairment reversal 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
Additions in the period (see note 9) 16,453 16,453
Depreciation expense (see note 9) (54,735) -
Impairment reversal (see note 9) 4,014 -
Interest expense - 27,673
Payments - (130,065)
Foreign exchange movements - (979)
As at 31 December 2024 373,464 335,256
Current 46,994
Non-current 288,262
335,256
The carrying value of the right-of-use assets include $340.9 million (2023:
$372.6 million) of oil and gas assets and $32.6 million (2023: $35.1 million)
of buildings.
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 27.
Amounts recognised in profit or loss
Year ended 31 December 2024 Year ended 31 December 2023
$'000 $'000
Depreciation expense of right-of-use assets 54,735 55,979
Impairment of right-of-use assets (4,014) (6,077)
Interest expense on lease liabilities 27,673 43,801
Rent expense - short-term leases 13,860 5,153
Rent expense - leases of low-value assets 33 113
Total amounts recognised in profit or loss 92,287 98,969
Amounts recognised in statement of cash flows
Year ended 31 December 2024 Year ended 31 December 2023
$'000 $'000
Total cash outflow for leases 130,065 135,675
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 2024
was $2.2 million (2023: $2.3 million).
The following table sets out a maturity analysis of lease payments, showing
the undiscounted lease payments to be received after the reporting date:
2024 2023
$'000 $'000
Less than one year 2,029 2,682
One to two years 858 2,011
Two to three years 860 872
Three to four years 875 873
Four to five years 882 889
More than five years 1,856 2,790
Total undiscounted lease payments 7,360 10,117
24. 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 2024 Year ended 31 December 2023
$'000 $'000
Deferred income 138,095 138,416
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 18(f)).
Proceeds from the farm-down 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.
25. Commitments and contingencies
Capital commitments
At 31 December 2024, the Group had commitments for future capital expenditure
amounting to $13.3 million (2023: $43.8 million). The key components of this
relate to commitments for the new stabilisation facility at Sullom Voe
Terminal and Magnus 2025 drilling campaign. 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 2024, the Group held surety bonds
totalling $277.0 million (2023: $250.4 million) to provide security for its
decommissioning obligations. See note 22 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.
26. Related party transactions
The Group financial statements include the financial statements of EnQuest PLC
and its subsidiaries. A list of the Group's principal subsidiaries is
contained in note 28 to these Group financial statements.
Balances and transactions between the Company and its subsidiaries, which are
related parties, have been eliminated on consolidation and are not disclosed
in this note.
All sales to and purchases from related parties are made at normal market
prices and the pricing policies and terms of these transactions are approved
by the Group's management. With the exception of the transactions disclosed
below, there have been no transactions with related parties who are not
members of the Group during the year ended 31 December 2024 (2023: none).
Within the $150.0 million term loan, which was fully repaid in October 2024,
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 was considered a smaller related party transaction under
Listing Rule 11.1.10 which ended on repayment of the term loan. Double A
Limited's share of the early repayment fee was $0.3 million.
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.
2024 2023
$'000 $'000
Short-term employee benefits 5,138 5,360
Share-based payments 124 144
Post-employment pension benefits 226 241
Termination payments 947 367
6,435 6,112
27. Risk management and financial instruments
Risk management objectives and policies
The Group's principal financial assets and liabilities comprise trade and
other receivables, cash and cash equivalents, interest-bearing loans,
borrowings and leases, derivative financial instruments and trade and other
payables. The main purpose of the financial instruments is to manage cash flow
and to provide liquidity for organic and inorganic growth initiatives.
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 Group is also exposed to interest rate risks related
to SOFR on cash balances and the RBL. As the RBL was undrawn at 31 December
2024, no sensitivities have been provided. 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 2024 and 2023, 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 2024 are disclosed in note 18. As of 31 December 2024, the Group
held financial instruments (options and swaps) related to crude oil that
covered 4.4 MMbbls of 2025 production and 1.3 MMbbls of 2026 production. The
instruments have an effective average floor price of around $69/bbl in both
2025 and 2026. 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 2024.
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 2024 (47,600) 47,200
31 December 2023 (4,000) 7,400
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 and any UK EPL cash tax payments 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 12% (2023: 22%) of the Group's sales and 97% (2023: 95%)
of costs (including operating and capital expenditure and general and
administration costs) are denominated in currencies other than the functional
currency.
The Group also enters into foreign currency swap contracts from time to time
to manage short-term exposures. The following tables summarise the Group's
financial assets and liabilities exposure to foreign currency.
Year ended 31 December 2024 GBP MYR Other Total
$'000 $'000 $'000 $'000
Total financial assets 219,758 22,570 3,024 245,352
Total financial liabilities 455,128 21,731 3,801 480,661
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 479,819 9,801 1,295 490,915
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 2024 (19,956) 19,956
31 December 2023 (20,398) 20,398
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 2024, there were no trade receivables past due
but not impaired (2023: nil) and no joint venture receivables past due but not
impaired (2023: nil). Receivable balances are monitored on an ongoing basis
with appropriate follow-up action taken where necessary. Any impact from ECL
is disclosed in note 15.
Ageing of past due but not impaired receivables 2024 2023
$'000 $'000
Less than 30 days - -
30-60 days - -
60-90 days - -
90-120 days - -
120+ days - -
- -
At 31 December 2024, the Group had two customers accounting for 91% of
outstanding trade receivables (2023: one customer, 58%) and four joint venture
partners accounting for over 70% of outstanding joint venture receivables
(2023: no joint venture partner).
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 2024,
$194.3 million (2023: $166.2 million) was available for drawdown under the
Group's facilities (see note 17).
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 21). 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, are unsecured.
Year ended 31 December 2024 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 - 34,168 - - - 34,168
Bonds - 69,095 69,095 701,197 - 839,387
Contingent consideration - 20,675 64,877 265,854 425,027 776,433
Obligations under lease liabilities - 66,092 71,600 222,093 31,696 391,481
Trade and other payables - 414,390 - - - 414,390
- 604,420 205,572 1,189,144 456,723 2,455,859
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 - 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 lease liabilities - 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
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 2024 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 - 546 8,908 999 - 10,453
Foreign exchange derivative contracts - 1,105 1,249 - - 2,354
Other derivative contracts - 23,902 3,802 1,928 - 29,632
- 25,553 13,959 2,927 - 42,439
Year ended 31 December 2023 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 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
Capital management
The capital structure of the Group consists of debt, which includes the
borrowings disclosed in note 17, 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 for downside protection and
growth initiatives. 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 (page
11).
2024 2023
$'000 $'000
Loans, borrowings and bond(i) (A) (see note 17) 666,073 794,453
Cash and cash equivalents (see note 13) (280,239) (313,572)
EnQuest net debt (B) (ii) 385,834 480,881
Equity attributable to EnQuest PLC shareholders (C) 542,466 456,728
Profit/(loss) for the year attributable to EnQuest PLC shareholders (D) 93,773 (30,833)
Adjusted EBITDA (F) (ii) 672,585 824,666
Gross gearing ratio (A/C) 1.2 1.7
Net gearing ratio (B/C) 0.7 1.1
EnQuest net debt/adjusted EBITDA (B/F) (ii) 0.6 0.6
Shareholders' return on investment (D/C) 17.3% N/A
(i) Principal amounts drawn, excludes netting off of fees and accrued interest
(see note 17)
(ii) See Glossary - non GAAP measures on page 70
28. Subsidiaries
At 31 December 2024, 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)4 Exploration, extraction and production of hydrocarbons England 100%
Stratic UK (Holdings) Limited(i)4 Intermediate holding company England 100%
EnQuest ENS Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest UKCS Limited(i)4 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 Dormant 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)4 Dormant England 100%
EnQuest UK Limited(i)4 Dormant England 100%
EnQuest Petroleum Developments Exploration, extraction and production of hydrocarbons Malaysia 100%
Malaysia SDN. BHD(i)3
EnQuest NNS Holdings Limited(i)4 Intermediate holding company England 100%
EnQuest NNS Limited(i)4 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)4 Intermediate holding company England 100%
EnQuest Forward Limited(i)4 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(i) 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).
Other than those listed below, all entities have a registered office address
as Charles House, 2nd Floor, 5-11 Regent Street, London, SW1Y 4LR United
Kingdom.
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
4 c/o BDO LLP, Temple Square Temple Street Liverpool L2 5RH - indicates
those legal entities that formally entered into the liquidation process during
October 2024
29. Cash flow information
Cash generated from operations
Notes Year ended 31 December 2024 Year ended
31 December 2023
$'000
$'000
Profit/(loss) before tax 166,614 231,779
Depreciation 4(c) 6,040 6,109
Depletion 4(b) 263,252 292,199
Exploration and appraisal expense 183 5,640
Net impairment charge to oil and gas assets 9 71,414 117,396
Net (write back)/disposal of inventory (5,539) (622)
Share-based payment charge 4(e) 983 3,320
Change in Magnus related contingent consideration 21 15,904 (10,811)
Change in provisions 22 39,116 59,970
Other non-cash income 4(d) - (4,058)
Change in Golden Eagle related contingent consideration 21 - 1,663
Unrealised (gain)/loss on commodity financial instruments 4(a) (3,090) (28,463)
Unrealised loss/(gain) on other financial instruments 4(b) 2,823 3,832
Unrealised exchange (gain)/loss (8,714) 12,401
Net finance expense 113,711 140,213
Operating cashflow before working capital changes 662,697 830,568
(Increase)/decrease in trade and other receivables (4,561) 51,724
(Increase)/decrease in inventories (5,786) (9,518)
Increase/(decrease) in trade and other payables 33,596 (18,028)
Cash generated from operations 685,946 854,746
Changes in liabilities arising from financing activities
Loans and borrowings $'000 Bonds Lease liabilities $'000 Total
$'000 $'000
At 1 January 2023 (413,528) (597,283) (482,066) (1,492,877)
Cash movements:
Repayments of loans and borrowings 289,684 138,052 - 427,736
Proceeds from loans and borrowings (190,657) - - (190,657)
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)
Cash movements:
Repayments of loans and borrowings((i)) 312,304 - - 312,304
Proceeds from loans and borrowings((ii)) (26,928) (160,000) - (186,928)
Payment of lease liabilities - - 130,065 130,065
Cash interest paid in year((iii)) 18,524 52,494 - 71,018
Non-cash movements:
Additions - 3,362 (16,453) (13,091)
Interest/finance charge payable (18,524) (54,971) (27,673) (101,168)
Fee amortisation (5,036) (3,493) - (8,529)
Foreign exchange and other non-cash movements (3,102) 2,742 980 620
At 31 December 2024 (33,972) (630,885) (335,255) (1,000,112)
(i)Repayments of loans and borrowings include $140.0 million repaid under the
RBL facility, $150.0 million term loan repayment and $22.3 million repaid
under the SVT working capital facility (note 17). In the Group Cash Flow
Statement, the repayment of loans and borrowings line does not include the
term loan repayment. This was fully repaid utilising the proceeds from the
high yield bond tap and as such is netted against the proceeds of the high
yield bond tap in the Group Cash Flow Statement on the proceeds from loans and
borrowings line (ii)Proceeds from loans and borrowing include $26.9 million
draw-downs under the SVT working capital facility and $160.0 million high
yield bond tap. In the Group Cash Flow Statement, proceeds from loans and
borrowings of $31.7 million includes amounts outlined in the table above less
the term loan repayment of $150.0 million, associated fees on termination $4.7
million and $0.4m relating to the high yield bond issue premium net of issue
fees. See note 17 for further details
(iii) The cash flow statement includes interest on decommissioning bonds and
Letters of Credit
Reconciliation of carrying value
Loans Bonds Lease liabilities (see Total
(see (see note 23) $'000
note 17) note 17) $'000
$'000 $'000
Principal (319,784) (474,669) (422,174) (1,216,627)
Unamortised fees 8,553 10,724 - 19,277
Accrued interest 21 (7,074) - (7,053)
At 31 December 2023 (311,210) (471,019) (422,174) (1,204,403)
Principal (33,972) (632,101) (335,255) (1,001,328)
Unamortised fees - 10,661 - 10,661
Accrued interest - (9,445) - (9,445)
At 31 December 2024 (33,972) (630,885) (335,255) (1,000,112)
30. Subsequent events
In January 2025, EnQuest announced that it had signed a Sale and Purchase
Agreement to acquire Harbour Energy's business in Vietnam, which includes the
53.125% equity interest in the Chim Sáo and Dua production fields. These
fields are governed by the Block 12W Production Sharing Contract, which runs
to November 2030 with an opportunity to extend. The transaction has an
effective date of 1 January 2024 and is scheduled to complete during the
second quarter of 2025. The headline value of the transaction is $84.0 million
and, net of interim period cash flows, the consideration to be paid by EnQuest
on completion is expected to equal c. $35 million. As at 1 January 2025, net
2P reserves and 2C resources across the fields total 7.5 million boe and 4.9
million boe, respectively.
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 to aid the
understanding of the Group's underlying financial performance, balance sheet
and cash flows by adjusting for certain items, as set out below, which impact
upon IFRS measures or, by defining new measures.
As set out in note 2, the Group no longer separately presents business
performance results and remeasurements and exceptional items. However, the
Group continues to adjust for material items consisting of income and expense
within its APMs which, because of the nature or expected infrequency of the
events giving rise to them or they are items which are remeasured on a
periodic basis, 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.
Adjusting items include, but are not limited to:
· Unrealised mark-to-market changes in the remeasurement of open
derivative contracts at each period end;
· Impairments on assets, including other non-routine
write-offs/write-downs where deemed material;
· Fair value accounting arising in relation to business combinations.
These transactions, and the subsequent remeasurements of contingent assets and
liabilities arising on acquisitions, including contingent consideration, do
not relate to the principal activities and day-to-day underlying business
performance of the Group; and
· Other items that arise from time to time that are reviewed by
management and considered to require separate presentation.
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.
Adjusted net profit attributable to EnQuest PLC shareholders (i) 2024 2023
$'000 $'000
Net profit/(loss) (A) 93,773 (30,833)
Adjustments - remeasurements and exceptional items :
Unrealised gains on derivative contracts (note 18) 267 24,631
Net impairment (charge)/reversal to oil and gas assets (note 9, note 10 and (71,414) (117,396)
note 11)
Change in Magnus contingent consideration (notes 4(d)) (15,904) 10,811
Movement in other provisions (notes 4(b) and note 4(d) - (1,717)
Insurance income on Kraken shutdown and PM8/Seligi riser incident (see note 1,663 4,127
4(d))
Write-off of exploration costs (see note 4(d)) (183) (5,640)
Drilling rig contract regret costs (see note 4(d)) (14,629) -
Pre-tax remeasurements and exceptional items (B) (100,200) (85,184)
Tax on remeasurements and exceptional items (C) 58,760 25,138
Post-tax remeasurements and exceptional items (D = B + C) (41,440) (60,046)
Adjusted net profit attributable to EnQuest PLC shareholders (A - D) 135,213 29,213
(i) APM changed from Business performance net profit to adjusted net profit,
which have been calculated on a consistent basis
Adjusted EBITDA is a measure of profitability. It provides a metric to show
earnings before the influence of accounting (e.g. depletion and depreciation),
financial deductions (e.g. borrowing interest) and other adjustments set out
in the table below. 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. 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 2024 2023
$'000 $'000
Reported profit from operations before tax and finance income/(costs) 311,528 397,373
Adjustments:
Unrealised gains on derivative contracts (note 18) (267) (24,631)
Net impairment charge/(reversal) to oil and gas assets (note 9, note 10 and 71,414 117,396
note 11)
Change in Magnus contingent consideration (notes 4(d)) 15,904 (10,811)
Insurance income on Kraken and PM8/Seligi riser incident (see note 4(d)) (1,663) (4,127)
Write-off of exploration costs (see note 4(d)) 183 5,640
Drilling rig contract regret costs (see note 4(d)) 14,629 -
Depletion and depreciation (note 4(b) and note 4(c)) 269,292 298,308
Inventory revaluation (5,539) (622)
Change in decommissioning and other provisions (note 4(b) and note 4(d)) 7,078 34,481
Net foreign exchange (gain)/loss (note 4(d)) (9,975) 11,659
Adjusted EBITDA (E) 672,584 824,666
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 page 16.
Total cash and available facilities 2024 2023
$'000 $'000
Available cash 226,317 313,028
Restricted cash 53,922 544
Total cash and cash equivalents (F) (note 13) 280,239 313,572
Available credit facilities((i)) 248,356 518,794
Credit facility - drawn down - (290,000)
Letter of credit - utilised (note 17) (54,100) (43,545)
Available undrawn facility (G) 194,256 185,249
Total cash and available facilities (F + G) 474,495 498,821
((i))Includes amounts available under the RBL: $176.4 million (2023: $306.2
million), letters of credit: $54.1 million (2023: $43.5 million), term loan:
$nil (2023: $150.0 million), vendor loan facility providing capacity for
refinancing the payment of existing invoices up to an amount of £23.7
million: $17.9 million available (2023: $19.0 million in relation to a vendor
loan facility which expired on 1 January 2024)
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. It is an important
reference point for the Group's going concern and viability assessments, see
page 16. The Group's definition of net debt, referred to as EnQuest net debt,
excludes unamortised fees, accrued interest and the Group's 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 2024 2023
$'000 $'000
Loans and borrowings (note 17):
RBL facility - 135,080
Term loan facility - 146,367
SVT working capital facility 33,972 29,784
Bonds (note 17):
High yield bond 454,339 294,276
Retail bond 167,101 169,669
Accrued interest 9,445 -
Loans and borrowings (H) 664,857 463,945
Non-cash accounting adjustments (note 17):
Unamortised fees on loans and borrowings - 8,553
Unamortised fees on bonds 10,661 10,724
Accrued interest (9,445) -
Non-cash accounting adjustments (I) 1,216 19,277
Debt (H + I) (J) 666,073 794,453
Less: Cash and cash equivalents (note 13) (F) 280,239 313,572
EnQuest net debt (J - F) (K) 385,834 480,881
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 maintaining
balance sheet discipline.
EnQuest net debt/adjusted EBITDA 2024 2023
$'000 $'000
EnQuest net debt (K) 385,834 480,881
Adjusted EBITDA (E) 672,585 824,666
EnQuest net debt/adjusted EBITDA (K/E) 0.6 0.6
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.
Cash capital and decommissioning expense 2024 2023
$'000 $'000
Reported net cash flows (used in)/from investing activities (183,573) (262,695)
Adjustments:
Purchase of other intangible assets 1,138 876
Payment of Magnus contingent consideration - Profit share 48,466 65,506
Payment of Golden Eagle contingent consideration - Acquisition costs - 50,000
Proceeds from vendor financing facility receipt (107,518) -
Proceeds from Bressay farm-down (1,263) -
Interest received (10,101) (5,895)
Cash capital expenditure (252,851) (152,208)
Decommissioning expenditure (60,544) (58,911)
Cash capital and decommissioning expense (313,395) (211,119)
Adjusted free cash flow ('FCF') represents the cash a company generates, after
accounting for cash outflows to support operations and to maintain its capital
assets. It excludes movements in loans and borrowings, net proceeds from share
issues, the impact of acquisitions and disposals and shareholder
distributions. Currently, this metric is useful to management and users to
assess the Group's ability to allocate capital across a range of activities -
including investment shareholder distributions, transactions and debt
management.
Adjusted free cash flow 2024 2023
$'000 $'000
Net cash flows from/(used in) operating activities 508,769 754,244
Adjustments:
Purchase of property, plant and equipment (249,165) (141,741)
Purchase of oil and gas and other intangible assets (4,824) (11,343)
Payment of Magnus contingent consideration (48,466) (65,506)
Estimated cash tax on disposal proceeds((i)) 50,000 -
Interest received 10,101 5,895
Payment of obligations under finance lease (130,065) (135,675)
Interest paid (83,162) (105,877)
Adjusted Free cash flow 53,188 299,997
((i)) Estimated by reference to disposal proceeds of $141.4 million and the
EPL tax rate of 35%
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 2024 2023
$'000 $'000
Revenue from crude oil sales (note 4(a)) (L) 1,020,266 1,127,419
Revenue from gas and condensate sales (note 4(a)) 164,647 338,973
Realised (losses)/gains on oil derivative contracts (note 4(a)) (M) (12,907) (11,264)
Barrels equivalent sales 2024 2023
kboe kboe
Sales of crude oil (N) 12,554 13,714
Sales of gas and condensate(i) 2,400 4,107
Total sales 14,954 17,821
(i) Includes volumes related to onward sale of third-party gas purchases not
required for injection activities at Magnus
Average realised prices 2024 2023
$/Boe $/Boe
Average realised oil price, excluding hedging (L/N) 81.3 82.2
Average realised oil price, including hedging ((L + M)/N) 80.2 81.4
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 2024 2023
$'000 $'000
Total cost of sales (note 4(b)) 787,383 946,752
Adjustments:
Unrealised (losses)/gains on derivative contracts related to operating costs (2,823) (3,832)
(note 4(b))
Movement in contractor dispute provision note 4(d) - (1,818)
Depletion of oil and gas assets (note 4(b)) (263,252) (292,199)
(Charge)/credit relating to the Group's lifting position and inventory (note (2,172) 4,244
4(b))
Other cost of operations((i)) (note 4(b)) (136,318) (305,919)
Operating costs 382,818 347,228
Less: realised (losses)/gains on derivative contracts (P) (note 4(b)) (4,735) 2,839
Operating costs directly attributable to production 378,083 350,067
Comprising of:
Production costs (Q) (note 4(b)) 307,634 308,331
Tariff and transportation expenses (R) (note 4(b)) 70,449 41,736
Operating costs directly attributable to production 378,083 350,067
(i) Includes $125.7 million (2023: $294.0 million) of purchases and associated
costs of third-party gas not required for injection activities at Magnus,
which is sold on
Barrels equivalent produced 2024 2023
kboe kboe
Total produced (working interest) (S)((i)) 14,909 15,992
(i) Production 724 kboe associated with Seligi gas (2023: 220 kboe)
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 2024 2023
$/Boe $/Boe
Production costs (Q/S) 20.6 19.3
Tariff and transportation expenses (R/S) 4.7 2.6
Total unit opex ((Q + R)/S) 25.3 21.9
Realised loss/(gain) on derivative contracts (P/S) 0.3 (0.2)
Total unit opex including hedging ((P + Q+ R)/S) 25.6 21.7
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