REG - EnQuest PLC - Results for the year ended 31 December 2025
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RNS Number : 0418Y EnQuest PLC 25 March 2026
EnQuest PLC, 25 March 2026
Results for the year ended 31 December 2025 and 2026 outlook
Unless otherwise stated, all figures are in US Dollars.
Comparative figures for the Income Statement relate to the year ended 31
December 2024 and the Balance Sheet as at 31 December 2024.
Alternative performance measures are reconciled within the 'Glossary -
Non-GAAP measures' at the end of the Financial Statements.
EnQuest Chief Executive, Amjad Bseisu, said:
"In a volatile world, EnQuest stands out for its consistent operational
delivery, highly tangible reserves base, disciplined investment, and a
strategy anchored in diversified growth. Our position as a top quartile
operator, combined with a strengthened financial base and an increasingly
diversified portfolio, sets the stage for a pivotal period of growth across
the UK North Sea and South East Asia.
2025 was a busy year, in which we grew and diversified our operations. Asset
uptime averaged c.90%, and we grew production by 5.4% to deliver above the
upper end of our market guidance. We lowered our unit operating costs despite
a significant weakening of the US Dollar, and we executed multiple
fast-payback production investments. We grew rapidly in South East Asia,
integrating our new Vietnam business, bringing Seligi 1b gas onstream
(Malaysia) nine months ahead of schedule, and we were awarded licences in
Brunei and Indonesia.
In Q4 2025, we also refinanced our RBL, strengthening our banking group and
unlocking $200 million of additional liquidity (cash and undrawn facilities
totalling $679 million at 31 Dec 2025). The RBL and EnQuest's broader credit
positioning have since been further enhanced by the $60.0 million settlement
of the Magnus contingent consideration mechanism, which removes a $432.9
million balance sheet liability and unlocks for EnQuest c.$777 million in
additional undiscounted forward Magnus cash flow.
These actions ensured that we began 2026 with confidence and momentum.
Reflecting strong Peninsular Malaysia gas demand and robust well performance,
Seligi 1b is regularly delivering up to 40% above the field's contracted
volumes, and, having resolved third-party disruption to Magnus (due to extreme
North Sea weather), Group production has consistently exceeded 50 Kboed during
March. With production enhancement investment programmes scheduled for the
balance of the year, we reiterate our annual guidance target of 41 to 45
Kboed.
As we work to maximise the value of our existing assets, accelerate our
expansion in South East Asia, and use our advantaged UK tax position and
operating expertise to execute a material UK North Sea transaction, we expect
that continued successful delivery will be transformative, broadening our
production base, increasing cash flow and enhancing shareholder returns.
"Reflecting the resilience of our core business and our commitment to
sustainable shareholder returns, the Board has proposed an increased final
2025 dividend of approximately $20.0 million, subject to shareholder
approval."
2025 performance
§ EnQuest operates 97% of its asset portfolio, and in 2025, the Group
delivered another year of top quartile performance.
§ Production of 45,606 Boepd (including pro forma Vietnam volumes) was above
the top end of market guidance (pro forma 40,000 to 45,000 Boepd). Underlying
asset uptime of 89% was at the top end of sector performance.
§ Reported production for the year, which includes Vietnam volumes from 9
July, was 42,945 Boepd (2024: 40,736 Boepd).
§ 2P reserves totalled 162.5 MMboe (2024: 168.6 MMboe) at year end; 78% of
which are in the highly tangible 1P (proven) volume category.
§ Investment in fast payback projects grew and diversified production, whilst
lowering unit costs and reducing emissions.
§ UK production remained within 4% of 2024 volumes. Magnus output rose 8%, to
15.3 Kboed, despite a five-week third-party infrastructure outage. Excluding
this outage, North Sea production efficiency was 92%.
§ In July, EnQuest completed the acquisition of Harbour Vietnam. EnQuest has
already undertaken three proactive well investments at Block 12W, boosting net
average Q4 production to c.5.5 Kboed.
§ South East Asian production grew 13% year-on-year, and in December 2025
EnQuest commenced gas production from Seligi 1b (Malaysia), nine months ahead
of schedule. Full production (c.70 mmscf/d, 6.0 Kboed net) began in January
2026.
§ EnQuest became the first company to be named Malaysia Operator of the Year
in consecutive years at the PETRONAS Emerald Awards. EnQuest was also
recognised with an award for Abandonment Excellence in Malaysia.
§ New country entries enhance diversified growth across South East Asia,
targeting c.35 Kboed in net production in the region by 2030.
§ Brunei Darussalam - awarded operatorship of the Block C PSC in July, where
EnQuest plans to deliver c.15 Kboed of gas production by 2029 (structured
around a 50:50 JV with the Brunei government).
§ Indonesia - awarded operatorship and a 40% interest in the Gaea and Gaea II
PSCs in August. With prospectivity of more than 100 Tcf across multiple
prospects, and the bp Tangguh partnership a 40% partner, the blocks are well
positioned to access LNG markets.
Financial highlights
§ Reserve Based Lending facility refinanced in Q4 2025. Backed by eight
leading banks, the $800 million facility provides significant transactional
capacity ($400 million loan tranche) and simplifies management of UK
decommissioning security ($400 million letter of credit tranche). Both
tranches can be increased by $400 million, via an $800 million accordion.
§ With the RBL fully undrawn at year end, cash and available facilities
totalled $678.6 million (31 December 2024: $474.5 million).
§ EnQuest net debt of $433.9 million (31 December 2024: $385.8 million)
followed payment in H2 2025 of UK EPL tax of $104.1 million; $22.7 million on
completion of the Vietnam acquisition and RBL refinancing fees totaling $17.8
million.
§ Revenue and other income totalled $1,118.3 million (2024: $1,180.7
million), with adjusted EBITDA of $503.8 million (2024: $673.9 million). Both
figures reflect lower oil revenues, with Brent falling 15% year-on-year. Cost
discipline and active hedging held operating costs flat, despite a 10%
weakening of the US Dollar.
§ Net $238.9 million gain on settlement of the Magnus contingent
consideration simplifies EnQuest's balance sheet.
§ Reported profit after tax of $1.6 million (2024: $93.8 million) includes
the impact of the two-year extension of EPL. Stripping out this non-cash item,
the profit after tax would have been $125.5 million.
§ Capital investment $179.2 million (2024: $252.9 million), inclusive of
c.$40 million in Seligi 1b growth capex. Decommissioning expenditure $56.8
million (2024: $60.5 million), focused on well plugging and abandonment and
Heather topsides removal.
§ The Group declared its maiden dividend of c.$15 million, which was paid in
June 2025.
2026 outlook
§ EnQuest is focused on delivering continued operational excellence and
value-accretive transactions in the UK and in South East Asia.
§ Credit-enhancing settlement of the Magnus contingent consideration,
completed in February for $60.0 million.
§ By crystallising payments that would otherwise have been payable over time
(valued at $432.9 million on a discounted basis at 30 June 2025), this
settlement unlocks the full upside of one of the Group's core assets.
§ A six-well Magnus infill drilling programme and production-enhancing well
interventions are due to commence in Q2 2026.
§ Net Group production is expected to average between 41,000 and 45,000
Boepd.
§ Production to end February averaged 32,429 Boepd, including the deferral of
c.650 kbbls (c.11,000 Boepd) due to a five-week third-party infrastructure
outage at Magnus. In March, Group production has consistently exceeded 50,000
Boepd.
§ In Malaysia, EnQuest is producing increased Seligi gas volumes to support
rising and sustained Peninsular Malaysia demand. March gross gas volumes have
regularly reached c.100 mmscf/d, materially exceeding the nominated contract
volume of 70 mmscf/d.
§ Operating expenditure expected to total c.$450 million; capital investment
expected to total c.$160 million; Decommissioning expenditure expected to
total c.$60 million.
§ From 1 April 2026, EnQuest has hedged a total of 5.1 MMbbls for the next 12
months with an average floor price of $71.3/bbl and a further 3.5 MMbbls in
the subsequent 12-month period with an average floor price of $64.4/bbl,
predominantly utilising swaps.
§ The Group is pleased to propose a 2025 final dividend of 0.8 pence per
share, equivalent to c.$20 million, payable in June 2026 following shareholder
approval at the Group's Annual General Meeting.
Production and financial information
Macro conditions 2025 2024 Change
Brent oil price(4) ($/bbl) 68.2 80.5 -15.3%
Natural gas price(5) (GBp/Therm) 88.3 83.6 +5.6%
Alternative performance measures ('APMs') 2025 2024 Change
Production (Boepd) 42,945 40,736 5.4%
Realised oil price ($/bbl)(1,2) 68.8 80.2 -14.2%
Average unit operating costs ($/Boe)(2) 25.1 25.6 -2.0%
Adjusted EBITDA ($m)(2) 503.8 673.9 -25.2%
Cash expenditures ($m) 236.0 313.4 -24.7%
Capital(2) 179.2 252.9 -29.1%
Decommissioning 56.8 60.5 -6.1%
Adjusted free cash flow ($m)(2) 8.7 53.2 -83.6%
End 2025 End 2024
EnQuest net (debt)/cash ($m)(2) (433.9) (385.8) 12.5%
Statutory measures 2025 2024 Change
%
Reported revenue and other operating income ($m)(3) 1,118.3 1,180.7 -5.3%
Cost of sales ($m) (837.5) (787.4) 6.4%
Reported gross profit ($m) 280.8 393.3 -28.6%
Reported profit/(loss) after tax ($m) 1.6 93.8 -98.3%
Reported basic earnings/(loss) per share (cents) 0.1 5.0 -82.0%
Net cash flow from operating activities ($m) 362.7 507.6 -28.5%
Net increase/(decrease) in cash and cash equivalents ($m) (24.5) (27.7) 11.6%
Notes:
(1) Including realised gains of $8.7 million (2024: realised losses of $12.9
million) associated with EnQuest's oil price hedges
(2) See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP Measures' starting on page 61.
(3) Including net realised and unrealised gains of $53.9 million (2024: net
realised and unrealised losses of $9.8 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
Harry Cameron
Presentation to Analysts and Investors
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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 unlocking value from energy assets. Responsibly. As an independent
energy company with operations in the UK North Sea and across South East Asia,
the Group's strategic vision is to lead as a safe, efficient operator of
mature and underinvested oil and gas assets; sustainably extending field lives
and delivering superior value across the asset lifecycle, as part of a just
energy 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
A year defined by operational excellence, enhanced foundations and strategic
clarity
Against a backdrop of geopolitical volatility, elevated commodity prices and
macroeconomic uncertainty, EnQuest is focused on operational, financial and
commercial delivery to maximise the value of our asset portfolio, expand scale
and diversify our operations.
We are building on strong foundations. In 2025, our operational and financial
performance was robust, and we simplified and enhanced our balance sheet.
At a time when the UK fiscal regime remains challenging, we also took decisive
steps to accelerate our diversification into high-growth Asian markets.
Having accelerated the Seligi 1b gas project through targeted investment, we
are now providing increased volumes to support Peninsular Malaysia demand,
driving Group production above 50,000 Boepd in March.
Accordingly, we have entered 2026 confident in our people, our relationships
and our assets, and with enhanced financial strength. With cash and undrawn
facilities totalling $678.6 million, we are well-positioned in both the UK
North Sea and South East Asia to deliver both organic and acquisitional
growth.
Delivering safe, reliable performance across our portfolio
EnQuest delivered another impressive operational year. Group production
exceeded the top end of our 40-45 Kboed pro forma guidance range at 45,606
Boepd, including the impact of our Vietnam acquisition. Underpinned by our
operational expertise, Group production efficiency remained high at around
90%, and we continued to build on our track record of extracting value from
late-life assets.
§ The Kraken field continued to perform at the very top of the production
efficiency for floating hubs, the FPSO's 95% production efficiency exceeding
North Sea average efficiency by c.28%.
§ Magnus increased year-on-year production by 8%, despite the impact of a
five-week third-party infrastructure outage in the first half. 2025 uptime,
excluding the third-party outage, was 93%, and the asset team completed a
successful two-infill well drilling campaign.
§ Settlement of the Magnus contingent consideration mechanism significantly
enhances our balance sheet and demonstrates our long-term commitment to this
core asset.
§ In Malaysia, we expanded production by c.13%, with 93% production
efficiency, and the benefit of new infill wells, idle well reinstatements and
strong domestic gas demand.
§ The nine-month acceleration of the Seligi 1b gas project exemplified our
ability to enhance asset value, and we have continued to action modifications
which further optimise gas production potential. Thus far in 2026, we have
regularly provided more than 100 mmscf/d of gas to support Peninsular
Malaysian demand, exceeding contractually nominated volumes by c.40%.
§ With 452 MMboe of 2C resources in place at 31 December 2025, we continue to
develop pathways to mature contingent resources into the 2P category.
§ We successfully integrated our Vietnam acquisition and immediately deployed
our operating expertise, proactively completing three well workovers that
enhanced production in the second half of 2025.
§ EnQuest also continued to advance its programme of decommissioning,
completing the well campaigns at both Thistle and Heather, and removing
Heather's topsides in a single 15.3 kTonne lift.
I was proud that in 2025 EnQuest was again named Malaysia Operator of the Year
by PETRONAS, becoming the first operator to win this award in successive
years. In 2025, EnQuest also became the first company to be awarded the
Offshore Energies UK 'Excellence in Decommissioning' award twice.
These successes reflect a capability we consider core to our identity and how
we create value: the ability to operate complex assets efficiently, safely and
responsibly, through the full asset lifecycle.
Strategic progress: diversifying the portfolio and expanding our footprint
We also made significant strides in broadening our geographic and commodity
exposure.
The accelerated expansion of our Seligi gas agreement and new country entries
into Vietnam (through the Block 12W acquisition), Brunei Darussalam (via the
Block C PSC award), and Indonesia (through the Gaea and Gaea II exploration
blocks), all advance our strategy to develop a balanced portfolio anchored in
predictable, high-quality operations.
Post-year end, we received a Letter of Award for a participating interest in
the Cendramas PSC as part of the 2026 Malaysia Bid Round, further
demonstrating our reputation as a highly respected counterparty across the
region.
These strategic steps underpin the Group's expectation that at least 35 Kboepd
of net production will come from South East Asia operations by 2030.
Financial discipline enabling shareholder returns and future growth
Global macroeconomic conditions in 2025 were shaped by uncertainty around US
trade policy, risks to economic growth and the likelihood of excess crude
supply. Brent crude prices remained subdued throughout the year, averaging in
the mid $60s to low $70s per barrel.
2025 revenue and other operating income was c.5% lower year-on-year, primarily
driven by a 15% decrease in oil prices, but EnQuest maintained stable
production costs and delivered adjusted EBITDA of $503.8 million.
Post-tax profit of $1.6 million reflects the sector-wide impact of the UK
government's decision in 2024 to extend the Energy Profits Levy ('EPL') by two
years to 31 March 2030. Stripping this non-cash adjustment out, post tax
profit was $125.5 million.
Our commitment to cost control, efficiency and capital discipline meant that
the Group delivered on its cost guidance, despite the pressures arising from a
material weakening in the US Dollar. I was also pleased that in June 2025,
EnQuest paid its first dividend, returning $15.3 million to shareholders.
In the fourth quarter of 2025, the Group executed a refinancing of our Reserve
Based Lending ('RBL') facility, establishing a six-year facility totalling
$800.0 million. Supported by eight leading international banks, including
long-standing existing lenders and high-quality new relationships, the new RBL
provides significant transactional capacity via the $400.0 million loan
tranche and simplifies management of UK North Sea decommissioning security
through the $400.0 million letter of credit tranche. An accordion of up to
$800.0 million allows each tranche to increase by up to $400.0 million.
This facility, and the broader credit positioning of EnQuest, are further
enhanced by the recent settlement of the Magnus contingent consideration. The
$60.0 million settlement removes a $432.9 million liability from our balance
sheet, unlocking for EnQuest c.$777 million in additional undiscounted forward
Magnus cash flow.
With greater financial flexibility and a strengthened balance sheet, the Board
is pleased to propose a dividend of 0.8 pence per share for 2025.
Navigating a shifting geopolitical landscape
Current geopolitical tensions underline the continued reliance of the world
economy on hydrocarbons and the strategic importance for countries to have
their own domestic oil and gas supply, the current closure of the Strait of
Hormuz causing oil prices to spike above $100/bbl for the first time since
2022.
The volatility of current conditions reinforces the importance of EnQuest's
focus on disciplined capital allocation, operational excellence and continued
diversification of our portfolio. Our focus remains on extracting value from
our core North Sea and South East Asian assets while maintaining financial
resilience in a market characterised by underlying modest demand growth and
elevated supply. This macroeconomic environment underscores the strategic
importance of pursuing value-accretive opportunities that strengthen cash flow
and support long-term shareholder returns.
The UK remains a fiscal outlier among nations by persisting in taxing windfall
profits, even when prices have been below historic averages. This has impacted
confidence in the UK North Sea, with operators cutting investment,
accelerating the cessation of production on assets, and consolidating
activities in what they consider to be a non-core region into joint ventures.
Although the UK Government missed an opportunity to stimulate sector
investment in its 2025 Autumn Budget by continuing to apply the Energy Profit
Levy, the formulation of the Oil and Gas Price Mechanism ('OGPM') as a
permanent, fit-for-purpose windfall tax successor to EPL offers encouragement.
EnQuest sees the OGPM as a positive development for the sector, balancing
increased taxation during periods of elevated prices with an environment that
does not discourage investment. EnQuest continues to advocate for the
accelerated introduction of the OGPM, ahead of the current EPL sunset date of
31 March 2030.
The deployment of our operational expertise and advantaged fiscal position
remain very relevant to the UK North Sea, and we are confident they provide a
strong foundation from which to consolidate value.
In Asia, the value proposition for EnQuest is simple and clear. Every country
in which we operate is a growth economy, and each is structurally short
energy. We are well respected in the region, with a strong track record of
delivery. As we expand our operational footprint and deploy our differentiated
capabilities, we stand ready to meet the growing demands of the economies and
communities we serve.
Building a lower-carbon future while maintaining safe operations
EnQuest is an expert in building value in mature and underinvested oil and gas
assets, and we strongly believe that everything we do directly contributes to
a just and economic transition to a lower-carbon future.
We continue to make strong progress against our environmental commitments.
Since the 2018 baseline established by the NSTA's North Sea Transition Deal
('NSTD'), we have reduced our absolute UK Scope 1 and 2 emissions by more than
45%, providing a strong foundation for our commitment to reach net zero in
Scope 1 and Scope 2 emissions by 2040. As a result, we are tracking well ahead
of NSTD milestones and are closing in on the 2030 targeted reduction of 50%.
Work is ongoing to decarbonise existing portfolio infrastructure, including
the project to reduce Kraken fuel and flare through the development of the
Bressay gas cap, and two major transformation projects at the Sullom Voe
Terminal, including the New Stabilisation Facility and long-term power
solution, which together are expected to reduce terminal emissions by around
90%. We also remain the most active decommissioning operator in the UK North
Sea, delivering safe and efficient decommissioning across multiple major
projects. Importantly, we continue to build this expertise while the majority
of the cost of these activities is paid by the companies from which we
acquired our assets.
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.
Our transition plan is credible, and I was proud to see EnQuest awarded an A-
rating in the 2025 CDP Climate Change Survey, reflecting the Group's strong
governance, robust emissions management, and clear, transparent strategy to
manage climate-related risks and opportunities. EnQuest's A- was the single
highest score awarded globally within the oil and gas extraction and
production sector, making EnQuest the only company in this category to receive
CDP's leadership-level recognition.
Safety remains our top priority and licence to operate. I am pleased to say
that we saw a significant decrease in Lost Time Incidents during 2025,
returning to a level that significantly outperformed the North Sea average. We
are not complacent in this, however, and we are reinforcing our expectations
with employees and contractors to ensure that everyone working at an EnQuest
site is aligned with our commitment to SAFE Results.
Looking ahead: a transformational year for EnQuest
In 2026, our ambition is clear: maximise the value of our existing assets,
continue our disciplined expansion in South East Asia, and use our advantaged
UK tax position and operating expertise to execute a material UK North Sea
transaction. We expect that successful delivery against these value-led
targets will be transformative, broadening our production base, increasing
cash flow and enhancing shareholder returns.
Production to the end of February averaged 32,429 Boepd, including the
deferral of c.650 kbbls of Magnus production due to a third-party
infrastructure outage, caused by storm damage. Since full production was
reinstated at Magnus, Group production has consistently exceeded 50,000 Boepd,
giving us confidence that we will again deliver against our annual targets.
To proactively address the risk of third-party equipment downtime on Magnus
production, EnQuest is well advanced with plans to bypass the Ninian Central
Platform during 2027, securing Magnus' offtake route into the future.
Our position as a top quartile operator, combined with a strengthened
financial base and an increasingly diversified portfolio, sets the stage for a
pivotal period of growth.
Closing remarks
2025 showcased what EnQuest does best: delivering top-quartile operations,
employing disciplined financial management, and unlocking value. We enter 2026
with momentum, financial strength and a clear strategic direction. I remain
immensely proud of our people, whose commitment and expertise underpin every
success.
As we pursue a material UK transaction and continued international expansion,
we will remain guided by a single priority: delivering long-term value for our
shareholders while playing a responsible role in the evolving energy
landscape.
Operational review
2025 saw the Group deliver 89% production efficiency across its operated
portfolio.
EnQuest continues to demonstrate its differentiated operating capability,
founded on deep expertise in late-life asset management and complemented by
sector-leading decommissioning performance.
In all our activities, the safety and well-being of those working across
EnQuest's sites remains paramount. All personnel are empowered to act
decisively to ensure the Group's high standards of safe operations are
consistently upheld.
The Group remains focused on optimising the assets it operates and has an
established track record of extending the productive life of mature oil and
gas fields. This is achieved through disciplined maintenance programmes, the
effective management of critical production infrastructure, and the
high-quality execution of drilling and well intervention activities.
In parallel, EnQuest continues to progress initiatives to decarbonise its
portfolio. Projects at Magnus, Kraken and the Sullom Voe Terminal ('SVT') are
aimed at materially reducing the Group's carbon footprint while improving the
long-term cost base of our operations. These initiatives are an important
component in ensuring the Group's assets remain resilient and competitive
within an evolving regulatory environment.
As part of maximising value from operated assets, the Group recognises the
importance of planning and executing safe, efficient and cost-effective
decommissioning, typically beginning around five years ahead of the cessation
of asset production. Decommissioning is an increasingly important capability
for operators in mature basins worldwide, and one in which EnQuest is
demonstrating sector leadership.
The operational excellence in evidence across EnQuest's portfolio is
transferable and scalable, supporting the Group's growth ambitions both in the
UK North Sea and across South East Asia. It also underpins the Group's plans
to right-size and repurpose existing infrastructure, including the development
of SVT as a future decarbonisation and renewable energy hub.
Operational excellence
In delivering production uptime of 89% across its operated portfolio during
2025, EnQuest achieved a level of performance that sits at the very top end of
the UK North Sea sector.
Excluding the impact of a third-party infrastructure outage, which saw Magnus
production shut-in for five weeks, Group production efficiency was 92%.
The latest available benchmarked data from the North Sea Transition Authority
('NSTA') shows that production efficiency across the UKCS is 75%. EnQuest's UK
operated asset uptime was 87%.
Further, the NSTA UKCS production efficiency for floating hubs is 67%. At 95%
production efficiency, EnQuest's Kraken FPSO beats that by 28%.
This exemplary uptime performance extends to the Group's South East Asia
business, with 93% uptime at PM8/Seligi and 100% uptime in Vietnam.
UK Upstream
2025 UK operations performance summary
Production of 31,122 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,
offsetting the impact of natural field declines.
Kraken
2025 performance summary
The Kraken Floating, Production, Storage and Offloading ('FPSO') facility
delivered an exceptional production efficiency of 95% (2024: 96%) and water
injection efficiency of 93% (2024: 95.5%) for the year, resulting in average
2025 net production of 10,948 Boepd (2024: 12,759 Boepd). This is a testament
to the focus and collaboration between the EnQuest and Bumi Armada operational
teams, delivering production efficiency performance that is 28% above the
industry average benchmark for floating hubs (as measured against the latest
North Sea Transition Authority data).
The Kraken maintenance shutdown was deferred to 2026 to enable isolation
upgrades that will reduce the production impact associated with future planned
maintenance. 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.
2026 outlook
The asset team is focused on maintaining best-in-class FPSO production
efficiency through focused investment in maintenance and reliability
activities, while aiming to manage reservoir decline and fuel gas production
with water injection sweep optimisation. Work is ongoing to mature the Kraken
Enhanced Oil Recovery ('EOR') project during 2026. Following an initial round
of polymer testing, further work is ongoing to ensure the compatibility of
reservoir chemicals with topside process equipment. EOR represents a material
upside to Kraken's value, with base case incremental recoverable oil estimates
of more than 40 MMbbls gross.
The EnQuest team is also advancing a fuel gas import project that involves the
subsea tie-back of a Bressay gas well to the Kraken FPSO. By establishing an
alternative 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.
Significant progress has been made in aligning the technical development
scenario with the NSTA, and both a Bressay FDP and a Kraken FDPA are at an
advanced stage.
With c.33 MMboe of 2C resources, and Harbour Energy expected to replace
Waldorf as our field partner, EnQuest 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 2026, Kraken
production will be subject to natural field decline and the impact of a short
maintenance "pit-stop" shutdown planned in the third quarter of the year,
which has been reduced from 15 days through planned upgrades to isolations
between the two production trains.
Magnus
2025 performance summary
In 2025, Magnus delivered an 8% increase in asset production, achieving 15,335
Boepd (2024: 14,173 Boepd) despite a five-week third-party infrastructure
outage in the first half of the year. The annualised impact of this outage was
c.1.7 Kboed in deferred production; equivalent to the volume lifted within a
standard Magnus offtake. The production increase was underpinned by
exceptional production efficiency of 93% (2024: 83%) excluding third-party
downtime, and the proactive completion of key maintenance scopes during the
production shut-in meant that the seven-day maintenance shutdown originally
planned for the second half of the year was not required.
2025 asset production benefitted from a successful two-well infill drilling
programme, with both wells producing above mid-case expectations, well
interventions and well optimisation work. The period June to August 2025 saw
EnQuest deliver the best three-monthly oil production rate at Magnus since
early 2020, peaking at c.19 Kboed barrels of oil per day in mid-July. In
addition, the recommissioning of a fifth water injection pump provided a 20%
uplift in Magnus water injection capacity, with field average water cut
reduced back to 2017 pre-acquisition levels of around 85%.
2026 outlook
The Group plans to execute a six-well infill drilling programme at Magnus,
commencing in May 2026 and culminating in 2027. The programme includes well
targets in the Lower Kimmeridge Clay Formation ('LKCF') reservoir, which is
estimated to contain c.325 million barrels of oil in place. The Group is
targeting 10 MMbbls of production upside from the next production phase at the
LKCF. 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.
Storm damage at the third-party operated Ninian Central Platform ('NCP')
resulted in a five-week unplanned outage for all system users, including
Magnus, at the start of 2026. Production was reinstated on 22 February.
EnQuest is proactively addressing the risk of third-party equipment
unavailability to Magnus production and is progressing plans to facilitate a
bypass of NCP during 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 Emissions Reduction project in Q4 2024,
engineering work will continue in 2026. This project demonstrates EnQuest's
commitment to the decarbonisation of its portfolio.
Greater Kittiwake Area
2025 performance summary
At the Greater Kittiwake Area ('GKA'), 2025 production averaged 1,825 Boepd
(2024: 2,009 Boepd), largely in line with expectations. Solid operational
performance in the year was underpinned by production efficiency of 75% (2024:
77%) and included the efficient completion of the planned maintenance
shutdown.
2026 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, and in
parallel with 2026 production operations. This process will be managed in full
by EnQuest, with Shell having transferred its decommissioning operator role to
EnQuest during 2024.
Non-operated North Sea assets
2025 performance summary
2025 production across the Group's non-operated UK interests averaged 3,014
Boepd (2024: 3,646 Boepd), with asset performance continuing in line with the
Group's expectations.
2026 outlook
At Golden Eagle, a 41-day shutdown is planned during the third quarter.
At Alba, the most significant activity centres on decommissioning, with the
cessation of asset production planned during the summer.
South East Asia
PM8/Seligi, Malaysia
2025 performance summary
EnQuest was again named Malaysia Operator of the Year at the 2025 PETRONAS
Emerald Awards, becoming the first company to receive this prestigious
accolade in successive years. To be recognised in this way by PETRONAS is an
important validation of the Group's reputation as a top-tier operator, both in
Malaysia and across the South East Asia region and is a testament to the work
undertaken across the EnQuest Malaysia team.
Malaysian production averaged 9,201 Boepd, 12.9% higher than 2024. This
increase was driven by continued operational excellence and production
efficiency of 93% (2024: 94%), as well as a programme of infill drilling, idle
well restoration and well workovers.
Following the award of an expansion to its Seligi gas agreement, EnQuest has
successfully accelerated plans 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.
Demonstrating the Group's project delivery expertise, work to drill
recompletions on five existing wells and execute infrastructure modifications
was completed nine months ahead of schedule, with gas production beginning in
December 2025. EnQuest commenced full production at 70 mmscf/d in January
2026, with capacity now proven to increase gross production to c.100 mmscf/d,
supporting Peninsular Malaysian demand and helping the nation meet its growing
energy needs. These volumes also increase the gas component of EnQuest's
production, which aligns with the Group's strategic aim to reduce its overall
carbon intensity.
The EnQuest Malaysia decommissioning team was also recognised with an award
for Abandonment Excellence at the PETRONAS Emerald Awards, following the
successful execution of a six-well plugging and abandonment ('P&A')
campaign during 2024. In 2025, EnQuest completed the P&A of a further five
wells, with work commencing following the Seligi gas workover programme. This
takes the total number of completed P&A wells in Malaysia to 21.
EnQuest continued its excellent HSE performance in Malaysia during 2025,
reaching the milestones of over three years and seven million man-hours
without a lost time incident.
2026 outlook
The Group plans to drill further non-associated gas wells during 2026, as well
as a programme of well workover and idle well restoration activities.
A nine-day 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.
At DEWA, which is located around 60km offshore Sarawak, Malaysia, the Group's
operated acreage includes 12 discovered fields with significant gas
development potential. EnQuest is targeting a phased development, with Phase 1
expected to deliver net production of c.9 Kboed and c.28 MMboe of net
reserves. The Field Development and Abandonment Plan ('FDAP') and Final
Investment Decision ('FID') are planned for the second half of 2026, subject
to joint venture partner and regulatory reviews and approvals.
EnQuest received a Letter of Award ('LOA') for a participating interest in the
Cendramas PSC by Petronas. The terms of the LOA, subject to the finalisation
and signing of the Joint Operating Agreement and the Cendramas PSC, are
effective from 23 September 2026, with more details on the PSC to be provided
upon signing.
Block 12W, Vietnam
2025 performance summary
In July 2025, EnQuest completed the acquisition of Harbour Energy's business
in Vietnam, including a 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 had an effective date of 1 January 2024, with a headline value
of $85.1 million. Net of interim period cash flows, the consideration paid by
EnQuest was $25.7 million.
Having assumed operatorship of the Chim Sáo and Dua fields ('Block 12W') from
completion, EnQuest is deploying its proven late-life and FPSO asset
management expertise to maximise value and is working to progress discovered
resources into reserves. The Group executed three proactive well investments
in the second half of 2025, boosting net average production in the fourth
quarter to c.5.5 Kboed. Reported net production, on an annualised basis, was
2,622 Boepd, while pro forma production for 2025 was 5,283 Boepd. EnQuest has
delivered 100% production efficiency since taking over as operator.
2026 outlook
Having already enhanced production since assuming operatorship of the Chim
Sáo and Dua fields in July 2025, the PSC extension provides EnQuest and its
joint venture partners with the opportunity to access upside across Block 12W
and progress discovered resources into reserves, with prospectivity spread
across three gas discoveries and several additional targets.
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. In Vietnam, EnQuest has been successful in extending the Block 12W PSC
by four years to July 2034, on its existing terms.
Decommissioning
Performance summary
EnQuest's dedicated in-house decommissioning team delivered a landmark year in
2025, reinforcing its position as a leader in North Sea decommissioning. All
well plug and abandonment ('P&A') activities have now been successfully
completed at Heather and Thistle, marking a significant milestone in these
projects and a major step in the safe and efficient retirement of these
offshore assets. The Heather topsides were safely removed from the field,
while preparations for Thistle's removal progressed at pace, setting the stage
for the next phase of heavy-lift operations.
These achievements underscore EnQuest's commitment to operational excellence
and environmental responsibility as it continues to execute complex
multi-asset campaigns ahead of schedule and within budget.
Well decommissioning
Between 2022 and 2024, the latest period for which NSTA data is available,
EnQuest has completed 47% of all Northern and Central North Sea well P&A
activity, at a cost that is significantly below the basin average.
At both the Heather and Thistle fields, all P&A activities were completed
after three-and-a-half-year campaigns on each asset, with a total of 83
successfully abandoned. In 2025, the Thistle team executed the remaining seven
wells to Phase 2, with the main rig then recovering 11 conductors. The
remaining 13 conductors were recovered offline during a multi-year
conductor-pulling unit campaign. At Heather, the well P&A campaign was
completed in March 2025, with a total of 34 conductors successfully removed by
the main rig.
Throughout 2025, EnQuest has also progressed planning and engineering work on
the Kittiwake platform wells and subsea wells at Magnus and Alma Galia, while
continuing to discuss the future work programmes with the North Sea Transition
Authority.
Preparation for removal
Alongside the completion of P&A at Heather, the project team completed
final preparations in readiness for the Allseas Pioneering Spirit vessel
campaign to remove the topsides.
The Heather team disembarked safely from the platform, completing the asset
rundown efficiently following well P&A. Key tasks included cleaning the
topsides and utility rundown. The Allseas Oceanic CSV then carried out the
required leg-cutting work ahead of the arrival of the Pioneering Spirit
heavy-lift vessel. In August the Pioneering Spirit mobilised, lifted the
Heather topside, and offloaded it at the MARS disposal yard in Denmark.
At Thistle, the project team continued to demonstrate its ability to deliver
multiple key scopes simultaneously. EnQuest and Saipem teams worked closely
together, advancing engineering and planning for the pre-disembarkation
preparation phase, which commenced in April and continued throughout the year,
ahead of the future heavy-lift campaigns.
Subsea campaigns were also completed, covering essential inspection, repair
and maintenance activities, as well as conductor recovery, utilising a bespoke
conductor drill and pinning tool designed specifically for the Thistle
campaign.
2025 marked the final full year on the platform, with disembarkation planned
for the first half of 2026, upon completion of the extensive
pre-disembarkation preparations scope and platform run-down.
Asset removals
In 2025, significant preparatory work was completed, and Heather was
disembarked to allow Allseas and their Pioneering Spirit heavy lift vessel to
remove the topsides from the field.
The Heather project reached a major decommissioning milestone, following the
safe removal of the Heather Alpha topsides in August. The Allseas-owned
Pioneering Spirit heavy lift vessel removed the 15,300 tonne topsides in a
single lift; the largest single lift in the North Sea in 2025. The topsides
were transported to Denmark where 97% of all decommissioning waste is to be
reused or recycled.
The Heather jacket is scheduled for removal in 2027, which aligns with
previously agreed contractual execution windows.
Midstream
Safe, stable operations
Throughout 2025, 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.
Decarbonisation
The Group is focused on right-sizing SVT for future operations. During 2025,
EnQuest successfully advanced 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.
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, which will be retired once the grid connection is in place.
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 2025, EnQuest continued 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. A
world-first scope involved the removal of a redundant crude oil tank with roof
integrity issues, highlighting EnQuest's decommissioning expertise.
Furthermore, the removal of the facilities creates the opportunity to
repurpose areas of SVT for third-party use, including renewable energy
projects.
2025 emissions at SVT were improved year-on-year, following a period of
elevated flaring due to issues encountered with the site's gas compression
system, which resulted in flaring above the routine baseline levels. Following
the effective deployment of an engineering and repair solution, the
compression system was returned to full operations, resulting in a return to
lower process flaring and emissions. It should be noted that the impacted
compressor will be retired when the NSF is operational.
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. In 2025 the
numbers were increased with two apprentices in college and three working at
the terminal gaining valuable experience in 2025. The Group also continued
with its graduate programme in 2025, with one engineer successfully completing
the EnQuest Graduate scheme at SVT.
SVT supported a range of cultural and sporting events in Shetland in 2025,
including the Shetland Junior Golf Open and sponsorship of local table tennis
events, Shetland Rugby Club U18 Italy tour and Shetland Folk Festival. SVT was
proud to have sponsored Team Shetland and Ability Shetland to take part in the
Disability Summer Games in Stirling, in which 19 athletes from Shetland took
part.
Seven educational awards for the academic year 2024-2025 were made by the
Trustees of the Sullom Voe Terminal Participants' Tenth Anniversary Fund. Now
in its 37th 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 English
language and linguistics, energy transitions and sustainability, mathematics
and structural engineering.
As operator, EnQuest also offers a scholarship opportunity 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.
Electrification/Onshore wind
During 2024, Veri Energy identified and progressed an opportunity to develop
an onshore wind project on behalf of EnQuest, designed to harness Shetland's
exceptional wind resource to support decarbonisation and lower operating costs
at the Sullom Voe Terminal. The project advanced through front‑end
engineering and design in 2025, with a final investment decision expected in
2026.
E-fuels
In early 2025, Veri Energy launched a major initiative to evaluate investable
pathways for e-fuel production at Sullom Voe. Working with leading global
technology providers, the team assessed and de-risked the full value chain for
producing e-fuels from green hydrogen and biogenic CO2.
This work aims to unlock Scotland's potential to produce low-carbon fuels by
also harnessing Shetland's exceptional wind resource and the inherent
advantages of the terminal site, strengthening long-term energy security and
resilience. Support from Aberdeen's Net Zero Technology Centre, through its
Energy Hubs project, is enabling the development of an advanced operating
model for future e‑fuel facilities.
The assessment evaluated both methanol synthesis and Fischer-Tropsch pathways
using market-leading technologies. Following this analysis, the first phase
will prioritise the development of an e-methanol facility, with front-end
engineering and design expected to begin in 2026. E‑methanol was selected
due to its strong applicability for marine decarbonisation and its role as a
key feedstock for sustainable aviation fuel via methanol‑to‑jet
technology.
Additional workstreams commencing in 2026 will explore replication of the
e-methanol facility and future expansion into downstream e‑SAF production.
With a skilled local workforce and advantaged site conditions, the Sullom Voe
development has the potential to scale into a meaningful e‑fuels export
opportunity over time.
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 CO2 from
isolated emitters in the UK and Europe. CO2 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 2025, work included significant engagement with the NSTA to progress
the licences through early risk assessment and site characterisation, 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 CO2 emitters to permanently sequester carbon
beginning in the early 2030s.
Financial review
Introduction
Against an uncertain macro-economic backdrop, EnQuest has used the tangibility
of its hydrocarbon reserves and strength of its relationships to further
simplify and strengthen its balance sheet. The Group has also managed its
exposure to lower and more volatile oil prices and a weaker USD, through a
combination of hedging programmes, cost control and liquidity management.
These steps have enabled the Group to build a significant platform of
liquidity - that can be used to deliver both organic and transformational
growth.
In November, EnQuest successfully refinanced its Reserve Based Lending
Facility (the 'RBL'). Structured around a $400.0 million loan tranche and
$400.0 million letter of credit tranche, the new facility extends the
instrument's maturity to 2031; expands Group total liquidity ($678.6 million
at 31 December 2025; $474.5 million at 31 December 2024) and simplifies the
management of decommissioning obligations. An accordion of up to $800.0
million provides the potential to increase each tranche by up to $400.0
million.
In December 2025, EnQuest reached substantial agreement with bp to settle the
outstanding Magnus profit-share-related contingent consideration for $60.0
million (paid in February 2026). This credit enhancing transaction removes a
material liability from EnQuest's balance sheet (which had a discounted value
of $432.9 million at 30 June 2025) and opens significant additional RBL
capacity. By securing full economic value to Magnus, EnQuest has enhanced its
ability to optimise operational and strategic decisions over the life of the
field, simplified its balance sheet and removed future financial variability
associated with the mechanism.
To manage risk, EnQuest maintains a balanced programme of hedging. With
average Brent declining 15% in 2025 and the USD weakening 10%, the Group's
commodity and foreign exchange hedge programme delivered an aggregate $29.4
million of realised gains (2024: aggregate $10.0 million realised loss). From
1 April 2026, EnQuest has hedged a total of 5.1 MMbbls for the next 12 months
with an average floor price of $71.3/bbl and a further 3.5 MMbbls in the
subsequent 12-month period with an average floor price of $64.4/bbl, in each
case predominantly utilising swaps.
The Group reported an IFRS post-tax profit of $1.6 million for the year to 31
December 2025 (2024: $93.8 million profit). Underlying this figure, settlement
of the Magnus Contingent Consideration crystalised net other income of $391.3
million (pre-tax aggregate change in fair value of contingent consideration,
see note 21) and a net impairment reversal of $5.8 million (2024: $71.4
million charge) was largely offset by the non-cash deferred tax charges of
$152.4 million relating to the Magnus profit share settlement and the
previously reported $123.9 million non-cash adjustment due to extension of the
EPL 'windfall tax' by two years (from 31 March 2028 to 31 March 2030), lower
underlying profit before tax (driven by lower oil prices) and a higher current
year EPL tax charge of $84.1 million (2024: $10.3 million).
Free cash flow generation in the period was $8.7 million (2024: $53.2
million), reflecting lower oil revenues, higher UK tax payments and
growth-focused capex programmes at Magnus and PM8/Seligi. After payments made
in relation to the Group's maiden dividend, Vietnam acquisition and RBL
refinancing fees, EnQuest net debt increased by $48.1 million, to $433.9
million. With the RBL fully undrawn at 31 December 2025, cash and available
undrawn facilities were $678.6 million (31 December 2024: $474.5 million).
Income statement
Revenue
Group production averaged 42,945 Boepd, 5% higher than 2024. Underlying this
was strong asset uptime performance of c.90%, the contribution from the
acquisition of producing interests in Vietnam, and investment in low-cost,
quick-payback well work and production optimisation at Magnus and PM8/Seligi.
Partially offsetting these positives was a five-week shut in at Magnus,
related to a third-party infrastructure outage and natural field declines. Oil
accounted for 84.1% of this output (2024: 87.2%).
Brent crude oil prices declined 15% year-on-year to average $68.2/bbl (2024:
$80.5/bbl) while the average day-ahead UK gas price increased by 5% to 88.3
GBp/therm (2024: 83.6 GBp/therm). Excluding the impact of hedging, EnQuest
realised an average oil price of $68.1/bbl (2024: $81.3/bbl). Post-hedging,
the realised oil price was $68.8/bbl (14.2% lower than in 2024, $80.2/bbl).
Reflecting the above price and volume drivers, Group revenue in the period
totalled $1,118.3 million, a 5% reduction year-on-year (2024: $1,180.7
million). In this figure, oil contributed $858.2 million (16% lower
year-on-year, 2024: $1,020.3 million) and condensate and gas revenue
contributed $200.5 million (22% higher year-on-year, 2024: $164.6 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 offset through an equal and
opposite charge to cost of sales.
Tariffs and other income generated $3.6 million (2024: $2.6 million), which
includes income associated with the transportation of the initial Seligi 1a
associated gas agreement.
Having repositioned and expanded the Group's programme of hedging in H2 2024,
realised gains on commodity hedges in 2025 totalled $8.7 million, primarily
reflecting the gains on swap contracts (2024: loss of $12.9 million).
Unrealised gains on open commodity contracts (from mark-to-market movements)
totalled $45.2 million (2024: $3.1 million gain).
Note: For the reconciliation of realised oil prices see 'Glossary - Non-GAAP
measures' starting on page 61
Cost of sales
Reflecting the Group's South East Asian expansion, a weaker USD and higher
volumes and prices associated with third-party West of Shetland gas that
crosses the Magnus facility, cost of sales increased 6% to $837.5 million
(2024: $787.4 million).
Excluding the impact of the 'crossover' gas volumes (2025: $166.2 million;
2024: $125.7 million), cost of sales was held broadly flat, with the Group's
active foreign exchange hedging programme reinforcing the Group's continued
focus on cost control.
Similarly, production growth and the weaker USD increased underlying
production costs to $344.5 million (2024: $307.6 million). Inclusive of a
$19.7 million net realised hedging gain (2024: net losses of $4.7 million)
production costs increased by just 4%, with total operating costs up 3% at
$394.0 million (2024: 382.8 million). Unit operating costs fell by 2% to
$25.1/Boe (2024: $25.6/Boe).
2025 2024
$ million $ million
Production costs 344.5 307.6
Tariff and transportation expenses 69.2 70.5
Realised (gain)/loss on derivatives related to operating costs (19.7) 4.7
Operating costs1 394.0 382.8
Charge/(credit) relating to the Group's lifting position and hydrocarbon 17.4 2.2
inventory
Other cost of operations 179.6 135.0
Depletion of oil and gas assets 267.3 263.3
Other cost of sales (20.8) 4.1
Cost of sales 837.5 787.4
Unit operating cost2 $/Boe $/Boe
- Production costs 22.0 20.6
- Tariff and transportation expenses 4.4 4.7
Average unit operating cost (excluding gain/loss on derivatives) 26.4 25.3
Average unit operating cost (including gain/loss on derivatives) 25.1 25.6
Notes:
1 See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP measures' starting on page 61
2 Calculated using production on a working interest basis including
Seligi Associated Gas (1a)
The charge relating to the Group's lifting position and hydrocarbon inventory
for the year ended 31 December 2025 was $17.4 million (2024: $2.2 million),
reflecting the optimisation of oil sales from Magnus. Depletion expense
($267.3 million) was 2% higher than 2024 ($263.3 million), mainly reflecting
the impact of the Vietnam acquisition, and other cost of sales ($20.8 million)
reflects unrealised gains on foreign exchange and UKA forward contracts (2024:
$4.1 million losses).
Impairment
In the year, the Group recognised a non-cash net impairment reversal of $5.8
million (2024: $71.4 million charge). Contributing to this, a reversal of
$94.3 million at Kraken and an aggregate charge of $88.5 million for GKA,
Golden Eagle and Alba, were primarily driven by a combination of a reduction
in the discount rate to 9.0% (from 10.0% at 31 December 2024), reductions in
near-term oil price assumptions (reflecting market dynamics) and updated
production and cost profiles, including the impact of a weaker USD.
Other income and expenses
The Group recognised net other income in the period of $369.7 million (2024:
net other expense of $4.7 million). The majority of this figure relates to a
net $391.3 million non-cash credit that was triggered by EnQuest's agreement
with bp to settle the outstanding Magnus profit share element of contingent
consideration for $60.0 million (see note 21 for further detail). Lease income
in the period totalled $20.4 million (2024: $16.5 million). Offsetting this
income, was a non-cash foreign exchange revaluation loss of $28.3 million
(2024: $10.0 million foreign exchange revaluation gain), with a $14.5 million
non-cash net increase in the decommissioning provision of fully impaired
non-producing assets (2024: non-cash charge of $7.1 million). 2024 also
included a $14.6 million charge relating to the termination of a drilling rig
contract, which followed Waldorf Petroleum's decision to defer near-term
Kraken infill drilling, due to its financial circumstances.
Other expenses include costs associated with Veri Energy, which totalled $3.6
million in the year (2024: $1.7 million).
Adjusted EBITDA
Adjusted EBITDA for the year totalled $503.8 million, down 25% compared to the
same period in 2024 ($673.9 million). This reduction primarily reflects
changing production mix and lower oil revenue - driven by lower commodity
prices (see detail above).
EnQuest's net debt to last 12-month adjusted EBITDA ratio at 31 December 2025
equalled 0.9x (31 December 2024: 0.6x).
Adjusted EBITDA 2025 2024
$ million $ million
Profit/(loss) from operations before tax and finance income/(costs) 648.8 311.5
Net unrealised commodity, foreign exchange and UKA hedge (gain)/loss (77.5) (0.3)
Depletion and depreciation 272.4 269.3
Impairment (reversal)/charge (5.8) 71.4
Change in fair value of contingent consideration (387.1) 15.9
Net other expenses 21.9 21.6
Change in well inventories 2.8 (5.5)
Net foreign exchange revaluation loss/(gain) 28.3 (10.0)
Adjusted EBITDA1 503.8 673.9
Note:
1 See reconciliation of Adjusted EBITDA within the 'Glossary -
Non-GAAP measures' starting on page 61
Finance costs
EnQuest's overall net finance costs increased by 7%, to $155.4 million (2024:
$144.9 million).
Finance charges included interest on loans and borrowings of $75.3 million
(2024: $73.5 million), the unwinding of discounting on decommissioning and
other provisions (2025: $36.7 million; 2024: $31.2 million) and lease
liability interest costs (2025: $25.1 million; 2024: $27.7 million).
Refinancing fees, the amortisation of finance fees on loans and borrowings and
other financial expenses (including the cost for surety bonds that provide
security for decommissioning liabilities) totalled $27.5 million (2024: $27.1
million).
Finance income decreased to $9.2 million reflecting lower interest receivable
from bank balances (2024: $14.5 million).
Profit/loss before tax
Reflecting the movements above, the Group's profit before tax was $493.4
million (2024: profit of $166.6 million).
Taxation
The 2025 tax charge of $491.9 million includes a non-cash deferred tax charge
of $374.7 million and a current tax charge of $117.2 million.
As previously highlighted in the Group's results for the six months ended 30
June 2025, the deferred tax charge is heavily distorted by the non-cash impact
of the two-year extension to the EPL; resulting in a charge to EnQuest of
$123.9 million. The Group also recognised a further non-cash deferred tax
charge of $152.4 million, which relates to the Magnus profit share settlement,
and $98.4 million of other non-cash tax charges that reflect the utilisation
of EnQuest's strategic UK North Sea tax asset in the period and tax on
unrealised hedge gains.
The current cash tax charge, excluding prior year adjustments, includes $84.1
million related to the EPL (2024: $10.3 million), with the increase driven by
lower capital expenditure and reduced EPL investment allowances, partly
resulting from the abolishment of certain allowances from 1 November 2024.
The Group's income statement effective tax rate for the period was 99.7%
(2024: 43.7%), with the two-year extension to the EPL constituting 25.1% of
the Group's total 2025 effective tax rate.
EnQuest's strategic UK North Sea tax asset was estimated at $1,851.3 million
(gross) at 31 December 2025 (31 December 2024: $2,066.4 million (gross)). The
decrease reflects utilisation against UK upstream taxable profits.
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 EPL, noting however that the UK Government has indicated its intention to
end EPL earlier than the current March 2030 legislated sunset date. In the
Autumn Statement 2025, the UK Government announced that they will introduce
the Oil and Gas Pricing Mechanism, a revenue-based windfall tax to replace
EPL. EnQuest also pays cash corporate income tax on its Malaysian and Vietnam
assets.
Profit/loss for the period
EnQuest's total profit after tax was $1.6 million (2024: profit after tax of
$93.8 million). 2025 profit is heavily distorted by the significant non-cash
impacts of the UK Government's decision in October 2024 to extend EPL by two
years. Excluding this impact, EnQuest delivered an underlying profit for the
period of $125.5 million.
Earnings per share
The Group's reported basic earnings per share was 0.1 cents (2024 earnings per
share: 5.0 cents) and reported diluted earnings per share was 0.1 cents (2024
earnings per share: 4.9 cents).
Cash flow, EnQuest net debt and liquidity
Reported net cash flows from operating activities for the year were $362.7
million. This was 29% below the comparative period of 2024 ($507.6 million),
which primarily reflects lower oil revenues due to the 15% year-on-year
decline in Brent prices.
Reported net cash flows used in investing activities increased by $11.8
million, to $194.2 million. Whilst this figure includes the "one-off"
acquisition cost of Vietnam ($20.3 million), the 2024 figure of $183.6 million
included "one-off" receipts associated with the Bressay transaction of $108.8
million. Excluding these "one-off" items, net cash flows used in investing
activities decreased by $117.3 million, principally reflecting $73.7 million
lower capital expenditure (2025: $179.2 million; 2024: $252.9 million) and no
Magnus profit share payments (2024: $48.5 million).
Cash outflow on capital expenditure is set out in the table below:
Capital expenditure 2025 2024
$ million $ million
North Sea 128.0 230.4
Malaysia and Vietnam 48.5 19.0
Exploration and evaluation 2.7 3.5
179.2 252.9
The Group utilised $192.9 million of cash in financing activities (2024:
$352.9 million). Interest payments on the Group's borrowings totalled $97.0
million (2024: $83.2 million). $83.1 million was paid in relation to finance
leases (2024: $130.1 million), with the reduction versus 2024 primarily
reflecting the c.70% contractual step down in charges relating to the Kraken
FPSO, partially offset by lease payments associated with the Vietnam FPSO. In
2025, net borrowings totalled $6.0 million (2024: net repayments of $130.6
million). In the period, EnQuest also paid a maiden dividend, equivalent to
$15.3 million (2024: share buyback of $9.0 million).
Despite significantly lower oil prices, EnQuest generated $8.7 million of
adjusted free cash flow in 2025. This reflects higher cash tax payments and
production enhancing investments, alongside management's focus on cost
control, capital discipline and liquidity management. In aggregate, Group cash
and cash equivalents decreased by $11.3 million to $268.9 million (2024:
$280.2 million) and EnQuest net debt rose $48.1 million to $433.9 million
(2024: $385.8 million). Primary drivers of this net debt rise were payment for
the Vietnam acquisition ($20.3 million), payment of costs relating to the
refinancing of the Group's RBL facility ($17.8 million) and EnQuest's
inaugural dividend ($15.3 million).
The movement in EnQuest net debt was as follows:
$ million
EnQuest net debt 1 January 2025 (385.8)
Net cash flows from operating activities 362.7
Cash capital expenditure (179.2)
Net interest and finance costs paid (91.7)
Finance lease payments (83.1)
Dividend paid (15.3)
Vietnam asset acquisition (20.3)
RBL re-financing fees (17.8)
Other movements, primarily net foreign exchange on cash and debt (3.4)
EnQuest net debt 31 December 20251 (433.9)
Note:
1 See reconciliation of alternative performance measures within the
'Glossary - Non-GAAP measures' starting on page 61
EnQuest net debt 31 December 31 December 2024
2025 $ million
$ million
Bonds 644.4 632.1
Senior secured debt facility ('RBL') - -
Vendor loan facility 22.1 -
SVT working capital facility 36.3 33.9
Cash and cash equivalents (268.9) (280.2)
EnQuest net debt1 433.9 385.8
Note:
1 See reconciliation of EnQuest net debt within the 'Glossary -
Non-GAAP measures' starting on page 61
EnQuest continues to monitor the debt capital markets and would look to
opportunistically refinance its existing 2027 bond maturities, subject to
market conditions.
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 increased by 0.9% to $3,594.3 million (31 December 2024: $3,562.6
million). This was mainly driven by the acquisition of Vietnam assets, which
contributed additional PP&E of $47.1 million and higher receivables of
$152.5 million. The receivables were primarily associated with the Group's
share of contributions already paid into the abandonment fund held in Vietnam
(totalling $92.1 million) which was established to ensure that sufficient
funds exist to meet future abandonment obligations (recorded in provisions as
set out below) on Block 12W, partner share of the FPSO lease liability and
other receivables. Other financial assets increased by $71.8 million,
primarily reflecting mark-to-market gains on the Group's derivatives at 31
December 2025 (mark-to-market losses of $21.6 million at 31 December 2024 were
shown in liabilities). The Group's deferred tax asset decreased by $235.1
million, primarily as a result of the tax effect of the change in fair value
associated with the Magnus profit share contingent consideration and
utilisation of the carry-forward tax loss position.
Liabilities
Total liabilities increased by 1.5% to $3,066.3 million (31 December 2024:
$3,020.1 million). Decommissioning provisions increased by $174.0 million,
reflecting $89.1 million additional obligations in Vietnam following the
acquisition in July 2025 (offset by $92.1 million additional abandonment fund
receivables noted above) (see notes 15 and 22) and in Malaysia related to the
Seligi 1b gas project. Lease liabilities increased by $36.9 million, primarily
reflecting the Vietnam FPSO lease obligations acquired, while trade and other
payables also increased by $40.2 million, mainly in relation to the
acquisition of Vietnam. Loans and borrowings increased by $42.6 million,
reflecting drawdown of the vendor loan facility and foreign exchange movements
on the GBP retail bond. Deferred tax liabilities increased by $145.7 million,
primarily reflecting the impact on deferred tax from the two-year extension to
the UK EPL. These increases were in turn offset by the agreement with bp to
settle the Magnus profit share contingent consideration for $60.0 million,
which led to a net reduction in the fair value estimate of $391.3 million,
leaving a contingent consideration liability (including the Magnus-linked
decommissioning liability) of $84.6 million (31 December 2024: $473.3
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 2025 Annual Report.
Going concern
During 2025, EnQuest has continued to focus on optimisation of its capital
structure and the maximisation of its available transactional capacity.
In November, EnQuest signed a new six-year senior secured reserves-based
lending facility which replaced the previous RBL, providing the Group with an
enhanced capital structure that is simple, flexible and aligned with its
growth ambitions. Details of the amended facility are provided in note 17. In
February 2026, the Group made final settlement for the Magnus profit share
contingent consideration, securing 100% of future Magnus cash flows while
maintaining its limited exposure to future decommissioning expenditure at the
asset. This credit-enhancing settlement, simplifies the Group's balance sheet,
unlocks the full upside of one of EnQuest's core assets, and further secures
longer term capacity under its RBL.
EnQuest closely monitors and manages its funding position and liquidity
requirements throughout the year, including forecast covenant results. Cash
forecasts are regularly produced and discussed, with sensitivities considered
for, but not limited to, changes in crude oil prices (adjusted for hedging
undertaken by the Group), production rates and costs. These forecasts and
sensitivity analyses allow management to mitigate liquidity or covenant
compliance risks in a timely manner. Management have considered the impact of
the situation in the Middle East, particularly on future oil prices.
Reflecting the uncertainty as to how long the conflict and the period of
elevated oil prices will last, management have assumed in the Base Case that
the average oil price for the going concern period will be $70.0/bbl. Although
this is slightly higher than that used in its impairment assessment (see note
2) to reflect post year-end pricing trends, it is considerably below current
spot prices.
The Group's latest approved budget and long term plan underpins management's
base case ('Base Case'), upon which a reverse stress test has been performed.
This indicates that an oil price of c.$45.0/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
$63.0/bbl for 2026 and 2027;
§ 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 (the "going concern period").
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 2029. The viability assumptions are consistent with the going
concern assessment, with consistent plausible downside risks applied in a
Downside Case. This assessment has taken into account the Group's financial
position as at 24 March 2026, its future projections; the Group's bond
maturities, which occur within 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 17 to 25.
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 both the Group's Base
Case and Downside 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 2029.
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.
Commodity prices
A decline in oil prices would adversely affect the Group's operations and
financial condition. To mitigate oil price volatility, the Directors have
hedged future production volumes utilising mainly 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.
Access to capital
Prolonged low oil prices, cost increases and production delays or outages
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 and prioritisation of
debt reduction by remaining undrawn on its RBL at both 2024 and 2025
year-ends. The increase in available funds under the RBL following the recent
refinancing and the long-dated maturity profile of this facility, along with
the additional debt capacity expected to arise following settlement of the
Magnus profit share contingent consideration provide a material level of
funding within the viability period. With the Group's bonds maturing in the
fourth quarter of 2027, which is within the viability period, Management have
assumed, and are confident, that these will be successfully refinanced based
on the Group's strong track-record and ongoing investor appetite to invest in
the energy industry. Refinancing would likely occur well ahead of their
maturity, providing funding beyond the viability period.
Notwithstanding the principal risks and uncertainties described 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 2029. Accordingly, the Directors therefore support this viability
statement.
Oil and gas reserves and resources
EnQuest asset base as at 31 December 2025
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 2025 123.3 52.7 132.3 20.0 94.2 36.3 143.3 146.9 168.6
Revisions4 0.5 0.3 0.6 2.0 30.7 7.6 2.6 31.0 8.2
Production (10.5) (5.2) (11.4) (2.6) (1.7) (2.9) (13.1) (6.9) (14.3)
31 December 2025 113.3 47.8 121.5 19.5 123.2 41.0 132.8 171.0 162.5
2C resources
(working interest)1,2,7,8
1 January 2025 305.1 18.1 308.2 17.8 160.2 45.4 322.9 178.3 353.6
Revisions, additions and relinquishments (0.4) 0.0 (0.4) 21.1 403.7 98.9 20.7 403.7 98.5
31 December 2025 304.8 18.1 307.9 38.9 563.9 144.3 343.6 582.0 452.1
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 newly acquired Block 12W in Vietnam
5 The above proven and probable reserves include volumes that will
be consumed as fuel gas, including c.6.0 MMboe at Magnus, c.1.2 MMboe at Block
12W, c.0.6 MMboe at Kraken, c.0.1 MMboe at Golden Eagle and c.0.1 MMboe at
Scolty Crathes
6 The above 2P reserves at 31 December 2025 on an entitlement basis
is 152 MMboe (North Sea 122 MMboe and South East Asia 31 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 2025 include the volumes
associated with the Group's PSC award at Block 12W in Vietnam and Block C in
Brunei Darussalam
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 as to lead as a safe, efficient operator of mature and
underinvested oil and gas assets; sustainably extending field lives and
delivering superior value across the asset lifecycle, as part of a just energy
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.
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 driving
top quartile operational performance, maintaining a strong balance sheet,
targeting transformational growth and diversification of 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
§ 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 Sustainability and Risk Committee oversees the effectiveness of the
RMF and provides a forum for the Board to review selected individual risk
areas in greater depth, while the Audit Committee monitors internal financial
and IT-related controls.
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.
During 2025, and in preparation for reporting against the updated Provision 29
of the UK Corporate Governance Code (the 'Code') issued in January 2024, an
in-depth review of the principal risks facing the Company has been undertaken.
During this review, the Directors have concluded several of the principal
risks are unchanged from those described in the 2024 Annual Report and
Accounts. However, certain risks have been refined to more accurately capture
the underlying risk while others are no longer considered principal in nature
but remain part of the Group's wider risk universe and will continue to be
monitored. To reach this conclusion, the Directors considered the changes in
the external environment during the recent period that could threaten the
Company's business model, future performance, liquidity, and reputation.
The risks that are no longer considered principal in nature are: Competition;
Portfolio Concentration; International Business; JV Partners; Reputation; and
Human Resources.
The Directors also considered management's view of the current risks facing
the Company. Subsequently, reviews of the Group's 'Risk Library', which
captures all risk areas faced by the Group into several overarching risks was
undertaken. This review led to a refined risk library of 11 overarching risks
(from 19 previously) which the Directors and Management believe affords
appropriate focus to the key risks impacting the Group, whilst avoiding
duplication. The associated 'Risk Bowties', which are used to identify risk
causes and impacts, with these mapped against preventative and containment
controls used to manage the risks to acceptable levels, have also been
refined. These Risk Bowties remain a key element in assuring the effectiveness
of the Group's material risk controls and the 11 risks are to be reviewed over
a two-year period, prioritising those risks that require a new bowtie as well
as retained risks that are coming up for a two-yearly review to ensure they
remain fit for purpose.
The Board, 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 2025 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. An RMF
Performance report is produced and reviewed at each Sustainability and Risk
Committee meeting in support of this review.
Near-term and emerging risks
The Group's integrated approach to risk management 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. During the
year, eight Risk Bowties were reviewed.
Ongoing geopolitical situation
The Group is monitoring the current situation in the Middle East, focusing on
personal safety for its people located in the region. At the date of this
report, EnQuest's people are safe and there has been no material disruption to
our day -to-day activities. The Group has also 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.
Geographical diversification
The Group has successfully expanded its operational footprint in Malaysia and
the wider South East Asia region following the acquisition of operations in
Vietnam and the award of PSCs in Indonesia and Brunei. The Board is cognisant
that this expansion creates a wider risk universe for the organisation,
although such risks are mitigated by 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. At an operational level and as part of the
integration processes, management reviews the control environment in place to
ensure compliance and completeness, updating and/or replicating EnQuest's
existing controls as necessary.
Climate change risks
While not considered an emerging risk or discrete risk in its own right, 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
Price and Foreign Exchange, Health, Safety and Environment, Access to Capital
and Liquidity and Political, Regulatory and Fiscal Risk, 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.
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%
continual reductions 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.
Looking ahead, EnQuest is progressing 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 Kraken flaring and emission
reductions through a Bressay gas line to power Kraken operations.
EnQuest has reported on all of the greenhouse gas emission sources within its
operational control required under the Companies Act 2006 (see Strategic
Report and Directors' Report) Regulations 2013 and The Companies (Directors'
Report) and Limited Liability Partnerships (Energy and Carbon Report)
Regulations 2018.
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.
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 'Price and Foreign Exchange' risk on page
22), and/or a materially lower than expected production performance for a
prolonged period (see 'Production' risk on page 20 and 'Reserves Estimation
and Replacement' on page 22), 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 2025, EnQuest's Lost Time Incident frequency rate1 ('LTIF') of 0.69,
represented a significant year-on-year improvement (2024: 1.55). However, the
Group never finds it acceptable to incur LTIs and 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. All safety events were subject to
thorough investigation and no systemic failure was identified within EnQuest
systems.
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 2025, 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 (2024: Medium)
Likelihood
Medium (2024: 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 well-being of its people and assets. As a result, the potential impact and
likelihood remains in line with 2024. 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 (2024: Low)
Production
RISK
The Group's production is critical to its success and is subject to a variety
of risks, including: subsurface uncertainties; the complexities of 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 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 is developing plans for installing the Ninian bypass which will
secure the export route for Magnus and continues to explore the potential of
alternative transport options and developing hubs that may provide both risk
mitigation and cost savings.
The Group added diversified growth to its production base through the
accelerated delivery of gas from the Seligi 1b gas project and the acquisition
of the Block 12W production assets in Vietnam and continues to consider new
opportunities for expanding production having been awarded PSCs in Indonesia
and Brunei during 2025.
Potential impact
High (2024: High)
Likelihood
Medium (2024: Medium)
Change from last year
There has been no material change in the potential impact or likelihood.
Risk appetite
Low (2024: Low)
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
development, 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 optimised performance and 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.
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 (2024: Medium)
Likelihood
Medium (2024: Medium)
Change from last year
The potential impact and likelihood remains unchanged, reflecting the
successful accelerated delivery of the Seligi phase 1b gas project and strong
progress on Heather and Broom decommissioning activities, the Ninian bypass
and Bressay gas development projects going through internal stage gate
reviews, and decommissioning programmes and right-sizing projects at SVT
remaining in the execution phase.
Risk appetite
Medium (2024: 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.
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.
During 2025, the Group concluded the acquisition of Block 12W in Vietnam and
was awarded PSCs in Indonesia and Brunei. The Vietnam acquisition added c. 7.5
MMboe of net working interest 2P reserves and c. 4.9 MMboe of net working
interest 2C resources. The Block 12W PSC being extended to 2034 provides the
opportunity to access upside across Block 12W. Estimated net working interest
2C resources across the DEWA (Malaysia), Indonesia and Brunei PSCs is over 100
MMboe. The Group continues actively to consider potential opportunities to
acquire new production resources and development projects that meet its
investment criteria.
Potential impact
High (2024: High)
Likelihood
Medium (2024: Medium)
Change from last year
There is no change to the potential impact or likelihood of this risk. The
accelerated delivery of the Seligi Phase 1b project and completion of the
acquisition of Block 12W in Vietnam in 2025 are balanced by other aspects,
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.
Risk appetite
Medium (2024: Medium)
Price and Foreign Exchange
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. This risk also includes the potential impacts of
climate change on oil and gas supply and demand and recognises that other
macroeconomic factors, such as foreign exchange and carbon pricing, could
present a material risk to the business.
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 operator of mature and underinvested producing assets, the Group
prioritises associated investments which deliver near-term returns and is in a
position to adapt and calibrate its exposure to new investments according to
developments in relevant markets. The Group monitors oil price and foreign
exchange sensitivity relative to its 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 and
GBP:USD foreign exchange rates within the terms of its established policy (see
page 55). The Group's RBL facility also requires hedging of EnQuest's
entitlement sales volumes (see page 55). To mitigate oil price volatility, the
Directors have hedged a total of 5.1 MMbbls from 1 April 2026 for the next 12
months with an average floor price of $71.3/bbl and a further 3.5 MMbbls in
the subsequent 12-month period with an average floor price of $64.4/bbl, in
each case predominantly utilising swaps. From 1 April 2026 we have £119m
hedged at an average rate of 1.3276. 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
and the cost of emissions trading allowances, with the Treasury function
supporting management of foreign exchange exposure.
Further, the Group's focus on production efficiency supports mitigation
against a low oil price environment.
The Group's expansion into South-East Asia has targeted commodity
diversification. The gas weighting of these opportunities aligns with the
Group's strategic aim to reduce its overall carbon intensity.
Potential impact
High (2024: High)
Likelihood
High (2024: High)
Change from last year
The potential impact and likelihood remain high, reflecting the uncertain
economic outlook, including possible impacts from forecast surplus near-term
supply increases, 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 further new
supply. Further, oil and gas will remain an important part of the energy mix,
especially in developing regions.
Risk appetite
Medium (2024: Medium)
Access to Capital and Liquidity
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 pages 15 to
16.
APPETITE
The Group remains focused on maintaining a strong balance sheet and liquidity,
controlling costs and complying with its obligations to finance providers
while delivering shareholder value.
MITIGATION
EnQuest has continued to focus on optimisation of its capital structure and
the maximisation of its available transactional capacity. In November 2025,
EnQuest signed a six-year senior secured RBL facility totalling $800.0
million, comprising a $400.0 million secured multi-currency revolving loan
facility and a $400.0 million secured multi-currency revolving letter of
credit ('LoC') facility. This facility, which replaces the previous RBL,
provides the Group with an enhanced capital structure that is simple, flexible
and aligned with its growth ambitions. Further, during 2025, EnQuest expanded
its Surety Bond provider consortium.
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 (2024: High)
Likelihood
Medium (2024: Medium)
Change from last year
There is no change to the potential impact or likelihood. The Group's
successful refinancing of its RBL, expanded Letter of Credit facility,
continued strong relations with its Surety Bond provider consortium and
improved fiscal certainty in the UK, are balanced against a volatile oil price
environment, potential increases in the cost of emissions trading allowances
and other factors such as climate change, other ESG concerns and geopolitical
risks, which could impact investors' and insurers' acceptable levels of oil
and gas sector exposure.
Risk appetite
Medium (2024: Medium)
Political, Regulatory and Fiscal Environment, including Climate Change risk
RISK
Unanticipated changes in the political, regulatory or fiscal environment,
including those associated with climate change, 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.
The Group's exposure to country-specific risks is reduced through the Group's
strategy of diversifying into new geographies, although it is recognised this
does add exposure to new political, regulatory or fiscal risks.
All business development or investment activities recognise potential tax
implications and the Group maintains relevant internal tax expertise, seeking
external advice when appropriate.
At an operational level, the Group has procedures to identify impending
changes in relevant regulations to ensure legislative compliance.
Potential impact
Medium (2024: High)
Likelihood
Medium (2024: Medium)
Change from last year
There has been no material change in the potential likelihood, but the
potential impact has reduced given the successor UK "windfall tax" regime to
the EPL has been announced, with threshold implementation prices above many
external forecasts, and no impending material regulatory changes, including
those associated with climate change, known or anticipated.
EnQuest has entered into several new geographies during 2025, although many of
these remain at the early stages of development which reduces the level of
risk to EnQuest.
Risk appetite
Medium (2024: 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, internal communications 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 and implementing improvements
as necessary has continued during 2025, with internal audit reviews planned
for 2026. A number of actions were undertaken to further strengthen the
Group's controls, including the following:
§ Enhanced governance of IT controls across EnQuest to ensure standardised
operations
§ Vietnam and Malaysia cyber security assessments against EnQuest security
policies conducted, with remediation for identified gaps underway
§ Deployed a new security vulnerability management system which identifies
technical weaknesses enabling management to assess the level of security risk
and systematically reduce it
§ Security strengthened through actions to improve system access rights
(including relevant user groups and password updates)
Potential impact
Medium (2024: Medium)
Likelihood
High (2024: High)
Change from last year
There is no change to the impact or likelihood of this risk, although with
both the threat-actor landscape and detective, preventative and containment
controls continuing to evolve.
Risk appetite
Low (2024: Low)
PRODUCTION DETAILS
Average daily production on a net working interest basis 1 Jan 2025 to 1 Jan 2024 to
31 Dec 2025 31 Dec 2024
(Boepd) (Boepd)
UK Upstream
- Magnus 15,335 14,173
- Kraken 10,948 12,759
- Golden Eagle 2,736 3,328
- Other Upstream(1) 2,103 2,327
Total UK 31,122 32,587
Total Malaysia 9,201 8,149
Total Vietnam 2,622 -
Total EnQuest 42,945 40,736
(1) Other Upstream: Scolty/Crathes, Greater Kittiwake Area and Alba
KEY PERFORMANCE INDICATORS
2025 2024 2023
Brent oil price ($/bbl) 68.2 80.5 82.5
ESG metrics:
Group LTIF(1) 0.69 1.55 0.52
Scope 1 and Scope 2 Emissions (kilo-tonnes of CO(2) equivalent) 1,068.0 1,068.4 1,041.9
Business performance data:
Production (Boepd) 42,945 40,736 43,812
Unit opex (production and transportation costs) ($/Boe)(2) 25.1 25.6 21.7
Cash expenditures ($ million) 236.0 313.4 211.1
Capital(2) 179.2 252.9 152.2
Decommissioning 56.8 60.5 58.9
Reported data:
Cash generated from operations ($ million) 497.8 685.9 854.7
EnQuest net debt ($ million)(2) 433.9 385.8 480.9
Net 2P reserves (MMboe) 163 169 175
(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 61
Group Income Statement
For the year ended 31 December 2025
2025 2024
Notes $'000 $'000
Revenue and other operating income 4(a) 1,118,300 1,180,709
Cost of sales 4(b) (837,540) (787,383)
Gross profit/(loss) 280,760 393,326
Net impairment reversal/(charge) to oil and gas assets 9 5,819 (71,414)
General and administration expenses 4(c) (7,482) (5,702)
Other income/(expenses) 4(d) 369,697 (4,682)
Profit/(loss) from operations before tax and finance income/(costs) 648,794 311,528
Finance costs 5 (164,591) (159,422)
Finance income 5 9,224 14,508
Profit/(loss) before tax 493,427 166,614
Income tax((i)) 6 (491,865) (72,841)
Profit/(loss) for the year attributable to owners of the parent 1,562 93,773
Total comprehensive profit/(loss) for the year, attributable to owners of the 1,562 93,773
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 0.001 0.050
Diluted 0.001 0.049
The attached notes 1 to 31 form part of these Group financial statements.
((i)) Inclusive of a deferred tax charge of $374.7million (2024: $60.7
million) which includes a one-off non-cash impact of $123.9 million from the
two-year extension to the UK Energy Profits Levy enacted in March 2025 (2024:
$42.2 million from the change in Energy Profits Levy tax rate to 38% and
removal of investment allowances)
Group Balance Sheet
At 31 December 2025
Notes 2025 2024
$'000 $'000
ASSETS
Non-current assets
Property, plant and equipment 9 2,370,131 2,297,954
Goodwill 10 139,510 134,400
Intangible assets 11 24,615 20,563
Deferred tax assets 6(c) 271,375 506,481
Other receivables 15 128,166 2,102
Other financial assets 18 50,818 38,459
2,984,615 2,999,959
Current assets
Intangible assets 11 1,110 1,138
Inventories 12 32,759 48,976
Trade and other receivables 15 245,469 230,971
Current tax receivable 2,021 1,256
Cash and cash equivalents 13 268,846 280,239
Other financial assets 18 59,491 69
609,696 562,649
TOTAL ASSETS 3,594,311 3,562,608
EQUITY AND LIABILITIES
Equity
Share capital and premium 19 392,054 392,054
Treasury shares 19 (3,540) (4,425)
Share-based payments reserve 19 12,395 13,949
Capital redemption reserve 19 2,006 2,006
Retained earnings 19 125,144 138,882
TOTAL EQUITY 528,059 542,466
Non-current liabilities
Loans and borrowings 17 638,211 621,440
Lease liabilities 23 285,767 288,262
Contingent consideration 21 24,302 452,891
Provisions((i)) 22 877,954 710,976
Deferred income 24 138,095 138,095
Deferred tax liabilities 6(c) 250,364 104,698
2,214,693 2,316,362
Current liabilities
Loans and borrowings 17 69,253 43,417
Lease liabilities 23 86,323 46,994
Contingent consideration 21 60,318 20,403
Provisions((i)) 22 54,082 55,130
Trade and other payables 16 454,650 414,390
Other financial liabilities 18 10,391 21,580
Current tax payable 116,542 101,866
851,559 703,780
TOTAL LIABILITIES 3,066,252 3,020,142
TOTAL EQUITY AND LIABILITIES 3,594,311 3,562,608
( )
((i) Decommissioning provision includes EnQuest's share of the total Block 12W
decommissioning liability, noting $92.1 million has been pre-funded through an
abandonment fund held in Vietnam which is disclosed within non-current other
receivables )
The attached notes 1 to 31 form part of these Group financial statements.
The financial statements were approved by the Board of Directors and
authorised for issue on 24 March 2026 and signed on its behalf by:
Jonathan Copus
Chief Financial Officer
Group Statement of Changes in Equity
For the year ended 31 December 2025
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 2024 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 229 - - (229) - - -
Repurchase and cancellation of shares (2,006) - (4,425) - 2,006 (4,593) (9,018)
Share-based payment - - - 983 - - 983
Balance at 31 December 2024 131,508 260,546 (4,425) 13,949 2,006 138,882 542,466
Profit for the year - - - - - 1,562 1,562
Total comprehensive income for the year - - - - - 1,562 1,562
Transfer of shares to Employee Benefit Trust 19 - - 885 (885) - - -
Share-based payment 20 - - - (669) - - (669)
Dividend paid - - - - - (15,300) (15,300)
Balance at 31 December 2025 131,508 260,546 (3,540) 12,395 2,006 125,144 528,059
The attached notes 1 to 31 form part of these Group financial statements.
Group Statement of Cash Flows
For the year ended 31 December 2025
Notes 2025 2024
$'000 $'000
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations 29 497,819 685,946
Cash received/(paid) on sale/(purchase) of financial instruments 9,075 (10,306)
Net cash received for trading of other intangible assets 26,829 -
Cash paid for purchase of other intangible assets (6,472) (1,138)
Cash paid in relation to amounts previously provided for (481) (9,063)
Decommissioning spend (56,810) (60,544)
Income taxes paid (107,235) (97,264)
Net cash flows from/(used in) operating activities 362,725 507,631
INVESTING ACTIVITIES
Purchase of property, plant and equipment (175,025) (249,165)
Proceeds from farm-down - 1,263
Vendor financing facility repaid 18(f),24 - 107,518
Purchase of intangible oil and gas assets 11 (4,225) (3,686)
Payment of Magnus contingent consideration - Profit share 21 - (48,465)
Acquisition 30 (20,278) -
Interest received 5,286 10,100
Net cash flows (used in)/from investing activities (194,242) (182,435)
FINANCING ACTIVITIES
Proceeds from loans and borrowings 152,432 31,662
Repayment of loans and borrowings (146,451) (162,304)
Payment for repurchase of shares - (9,018)
Payment of obligations under financing leases 23 (83,061) (130,065)
Dividend paid 8 (15,300) -
Interest paid (96,997) (83,162)
Other finance expenses paid (3,606) -
Net cash flows (used in)/from financing activities (192,983) (352,887)
NET (DECREASE)/INCREASE IN CASH AND CASH EQUIVALENTS (24,500) (27,691)
Net foreign exchange on cash and cash equivalents 13,107 (5,642)
Cash and cash equivalents at 1 January 280,239 313,572
CASH AND CASH EQUIVALENTS AT 31 DECEMBER 268,846 280,239
Reconciliation of cash and cash equivalents
Total cash at bank and in hand 13 265,886 226,317
Restricted cash 13 2,960 53,922
Cash and cash equivalents per balance sheet 268,846 280,239
The attached notes 1 to 31 form part of these Group financial statements.
Notes to the Group Financial Statements
For the year ended 31 December
2025
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 2025 were
authorised for issue in accordance with a resolution of the Board of Directors
on 24 March 2026.
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 2025 and 2024
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 2025 and 2024 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 24 March 2026 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 2025.
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 which
impact upon IFRS measures or, by defining new measures. See the Glossary -
Non-GAAP Measures on page 61 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.
During 2025, EnQuest has continued to focus on optimisation of its capital
structure and the maximisation of its available transactional capacity.
In November, EnQuest signed a new six-year senior secured reserves-based
lending facility which replaced the previous RBL, providing the Group with an
enhanced capital structure that is simple, flexible and aligned with its
growth ambitions. Details of the amended facility are provided in note 17.
In February 2026, the Group made final settlement for the Magnus profit share
contingent consideration, securing 100% of future Magnus cash flows while
maintaining its limited exposure to future decommissioning expenditure at the
asset. This credit-enhancing settlement, simplifies the Group's balance sheet,
unlocks the full upside of one of EnQuest's core assets, and further secures
longer term capacity under its RBL.
EnQuest closely monitors and manages its funding position and liquidity
requirements throughout the year, including forecast covenant results. Cash
forecasts are regularly produced and discussed, with sensitivities considered
for, but not limited to, changes in crude oil prices (adjusted for hedging
undertaken by the Group), production rates and costs. These forecasts and
sensitivity analyses allow management to mitigate liquidity or covenant
compliance risks in a timely manner. Management have considered the impact of
the situation in the Middle East, particularly on future oil prices.
Reflecting the uncertainty as to how long the conflict and the period of
elevated oil prices will last, management have assumed in the base case that
the average oil price for the going concern period will be $70.0/bbl. Although
this is slightly higher than that used in its impairment assessment (see note
2) to reflect post year-end pricing trends, it is considerably below current
spot prices.
The Group's latest approved budget and long term plan underpins management's
base case ('Base Case'), upon which a reverse stress test has been
performed. This indicates that an oil price of c.$45.0/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 $63.0/bbl for 2026 and 2027;
· 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 (the "going concern period").
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:
· Lack of Exchangeability (Amendments to IAS 21)
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 and disclosure in financial statements
IFRS 19 Subsidiaries without Public Accountability: Disclosures
Other than IFRS18, 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, which is for periods commencing on or after 1 January 2027.
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 2025, 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 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 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 Price and Foreign Exchange Risk
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 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 or
impairment reversal 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 2025 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 half-year and, in 2025, the post-tax discount rate
was estimated at 9.0% (2024: 10.0%) 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 2025. 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 2024, 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.
Discounts or premiums are applied to price assumptions based on the
characteristics of the oil produced and the terms of the relevant sales
contracts.
When compared to the latest available Paris-consistent climate scenario
modelling data released by the World Business Council of Sustainable
Development ('WBCSD') in May 2024, EnQuest's assumption is broadly aligned
with the top end of a range of Paris-consistent scenario's. When compared to
the International Energy Agency's ('IEA') forecast prices under its Net Zero
Emissions by 2050 Scenario ('NZE') ,published in November 2025, which is also
considered a Paris-consistent scenario and maps out a pragmatic but ambitious
global pathway for the energy sector to achieve net zero CO2 emissions by 2050
and is consistent with a long-term goal of limiting the rise in global average
temperatures to 1.5 °C (with a 50% probability), EnQuest's short-term
assumptions are below those assumed under the NZE, while its medium and
longer-term prices are significantly higher. As further considered later in
this note, management believes a 10% reduction in crude oil price assumptions
to be a reasonably possible change and has provided an impairment sensitivity
on this basis. However, the potential impact of applying the IEA NZE Scenario,
which is just one view of the possible impact of climate change, would result
in a materially higher impairment charge. An inflation rate of 2% (2024: 2%)
is applied from 2030 onwards to determine the price assumptions in nominal
terms (see table below).
The price assumptions used in 2024 were $75.0/bbl (2025), $75.0/bbl (2026),
$75.0/bbl (2027) and $76.5/bbl real thereafter, inflated at 2.0% per annum
from 2028.
2026 2027 2028 2029>
Brent oil ($/bbl) 65.0 67.5 72.5 75.0
(· ) (Inflated at 2% from 2030)
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, 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 17) 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 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 $198.7 million, which is approximately 8% of the net book
value of property, plant and equipment as at 31 December 2025.
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 9.0% 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 2025
would have been approximately $51.9 million higher. If the discount rate was
one percentage point lower, the net impairment reversal would have been
approximately $24.3 million higher.
Goodwill
Irrespective of whether there is any indication of impairment, EnQuest is
required to test annually for impairment of goodwill acquired in business
combinations. The Group carries goodwill of approximately $139.5 million on
its balance sheet (2024: $134.4 million), principally relating to the
acquisitions of the Magnus oil field (acquired in 2018) in the UK and Block
12W in Vietnam (acquired in 2025). 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
Judgement: During 2025, management commenced discussions with bp to settle the
75% Magnus contingent consideration arrangement. Management assessed that the
agreement to settle the Magnus contingent consideration, signed and concluded
in February 2026, was substantially agreed with bp at 31 December 2025.
Therefore the agreement price of $60.0 million was deemed to be a reasonable
fair value in line with IFRS 13, for the contingent consideration as at 31
December 2025, resulting in a pre-tax gain of $391.3 million. If management
had concluded the agreement was not substantially complete at year end, the
contingent consideration would have continued to be valued based on the
present value of the future expected cash flows from the Magnus field, which
at 30 June 2025 resulted in a provision of $432.9 million being recorded.
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 Group assesses discount rates in
each geography in which it operates using an appropriate benchmark, usually
government bonds. As such, the nominal discount rate used to determine the
balance sheet obligations ranged from 3.1% to 4.5% (2024: 3.1% to 4.5%). Costs
at future prices are determined by applying inflation rates. The inflation
rates applied are usually managements estimate based on relevant in-country
benchmarking, but in certain circumstances inflation is applied in accordance
with the relevant operating agreement. As such, where inflation has been
applied to decommissioning costs, it has ranged between 1.0% and 2.0% per
annum thereafter (2024: 1.0% to 2.0%). The weighted average period over
which North Sea decommissioning costs are generally expected to be incurred is
estimated to be approximately 12 years.
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 sensitivity has only been run for
the UK North Sea segment given its materiality compared to Malaysia and
Vietnam. 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 $58.6 million (2024: $59.4 million). The pre-tax impact on the
Group income statement would be a charge of approximately $57.5 million (2024:
$58.7 million).
Business combination
Judgement: The Group determined that the acquisition of Block 12W in Vietnam
during the year was the acquisition of a business, due to the acquired set of
activities and assets including inputs and processes critical to the ability
to continue producing outputs.
Estimates: While the risk that the acquisition fair value of Block 12W in
Vietnam materially changes in the next 12 months is low and so is not
considered a key source of estimation uncertainty, for business combinations
the Group determines the fair value of property, plant and equipment acquired
based on the discounted cash flows at the time of acquisition from the proven
and probable reserves. In assessing the discounted cash flows, the estimated
future cash flows attributable to the asset are discounted to their present
value using a discount rate that reflects the market assessments of the time
value of money and the risks specific to the asset at the time of the
acquisition. In calculating the asset fair value, the Group will apply oil
price assumptions representing management's view of the long-term oil price.
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 2025, the Group had two significant operating
segments: the North Sea and Malaysia. The Vietnam, Indonesia and Brunei
operations, which are new for 2025, are not yet deemed significant in
accordance with the quantitative thresholds for separate disclosure under IFRS
8, and so these operations have been aggregated into one reporting group,
alongside other Corporate activities. Operations are managed by location and
all information is presented per geographical segment. The Group's segmental
reporting structure remained in place throughout 2025. 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 2025 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 895,313 114,110 52,842 1,062,265 - 1,062,265
Other operating income/(expense) 1,770 - 343 2,113 53,922 56,035
Total revenue and other operating income/(expense) 897,083 114,110 53,185 1,064,378 53,922 1,118,300
Income/(expenses) line items:
Depreciation and depletion (244,937) (18,183) (9,308) (272,428) - (272,428)
Net impairment reversal/(charge) to oil and gas assets 5,819 - - 5,819 - 5,819
Exploration write-off and impairments (173) - - (173) - (173)
Segment profit/(loss)(ii), (iii) 489,959 43,770 9,090 542,819 105,975 648,794
Other disclosures:
Capital expenditure(iv) 148,814 63,214 1,328 213,356 - 213,356
North Sea Malaysia All other segments Total Adjustments Consolidated
segments and
Year ended 31 December 2024 eliminations((i), (iii))
$'000
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
(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) The consolidated profit/(loss) figure reconciles with Profit/(loss) from
operations before tax and finance income/(costs) in the income statement. 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
2025 2024
$'000 $'000
Segment profit/(loss) before tax and finance income/(costs) 542,819 328,903
Finance costs (164,591) (159,422)
Finance income 9,224 14,508
Gain/(loss) on derivatives(i) 105,975 (17,375)
Profit/(loss) before tax 493,427 166,614
(i) Includes $28.5 million realised gains on derivatives (2024: $17.6 million
realised losses) and $77.5 million unrealised gains on derivatives (2024: $0.3
million). See note 18(b) for further detail
Revenue from three customers each exceeds 10% of the Group's consolidated
revenue arising from sales of crude oil, with amounts of $414.3 million,
$103.6 million and $93.0 million per each single customer (2024: three
customers; $394.8 million, $156.0 million, and $115.7 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 2025 Year ended
$'000 31 December 2024
$'000
Revenue from contracts with customers:
Revenue from crude oil sales 858,166 1,020,266
Revenue from gas and condensate sales(i) 200,526 164,647
Tariff revenue 3,573 2,644
Total revenue from contracts with customers 1,062,265 1,187,557
Realised gains/(losses) on commodity derivative contracts (see note 18) 8,744 (12,907)
Unrealised gains/(losses) on commodity derivative contracts (see note 18) 45,178 3,090
Other 2,113 2,969
Total revenue and other operating income 1,118,300 1,180,709
(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 2025 31 December 2024
$'000 $'000
North Sea Malaysia Vietnam Total North Sea Malaysia Vietnam Total
Revenue from contracts with customers:
Revenue from crude oil sales 703,071 103,299 51,796 858,166 900,310 119,956 - 1,020,266
Revenue from gas and condensate sales(i) 192,074 7,406 1,046 200,526 162,951 1,696 - 164,647
Tariff revenue 168 3,405 - 3,573 568 2,076 - 2,644
Total revenue from contracts with customers 895,313 114,110 52,842 1,062,265 1,063,829 123,728 - 1,187,557
(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 2025 Year ended
$'000 31 December 2024
$'000
Production costs 344,580 307,634
Tariff and transportation expenses 69,189 70,449
Realised (gain)/loss on derivative contracts related to operating costs (see (19,711) 4,735
note 18)
Unrealised (gains)/losses on derivative contracts related to operating costs (32,342) 2,823
(see note 18)
Other non-cash UKA losses 11,490 1,335
Change in lifting position 3,350 3,528
Crude oil inventory movement 14,057 (1,356)
Depletion of oil and gas assets(i) 267,299 263,251
Other cost of operations(ii) 179,628 134,984
Total cost of sales 837,540 787,383
(i) Includes $29.2 million (2024: $27.9 million) Kraken and Vietnam FPSO
right-of-use asset depreciation charge and $26.3 million (2024: $23.5 million)
of other right-of-use assets depreciation charge
(ii) Includes $166.2 million (2024: $125.7
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 2025 Year ended
$'000 31 December 2024
$'000
Staff costs (see note 4(e)) 73,634 75,833
Depreciation(i) 5,129 6,040
Other general and administration costs 26,359 26,748
Recharge of costs to operations and joint venture partners (97,640) (102,919)
Total general and administration expenses 7,482 5,702
(i) Includes $3.7 million (2024: $3.4 million) right-of-use assets
depreciation charge on buildings
(d) Other income/(expenses)
Year ended 31 December 2025 Year ended
$'000 31 December 2024
$'000
Net foreign exchange (losses)/gains (28,330) 9,975
Rental income from office sublease 1,893 2,201
Fair value changes in contingent consideration (see note 21) 387,145 (15,904)
Change in decommissioning provisions (see note 22) (9,727) (6,666)
Change in Thistle decommissioning provision (see note 22) (4,772) (412)
Drilling rig contract cancellation costs((i)) - (14,629)
Write-down of relinquished assets/unsuccessful exploration expenditure (see (173) (183)
note 11)
Insurance income (53) 1,663
Reversal of provisions 4,685 -
Other 19,029 19,273
Total other income/(expenses) 369,697 (4,682)
(i) In 2024, 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 2025 Year ended
$'000 31 December 2024
$'000
Wages and salaries 62,286 66,700
Social security costs 6,202 5,899
Defined contribution pension costs 5,932 5,265
(Credit)/expense of share-based payments (see note 20) (669) 983
Other staff costs 13,969 12,300
Total employee costs 87,720 91,147
Contractor costs 46,529 37,493
Total staff costs 134,249 128,640
General and administration staff costs (see note 4(c)) 73,634 75,833
Non-general and administration costs 60,615 52,807
Total staff costs 134,249 128,640
The monthly average number of persons, excluding contractors, employed by the
Group during the year was 694, with 359 in the general and administration
staff costs and 335 directly attributable to assets (2024: 673 of which 336 in
general and administration and 337 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 2025 and for the
comparative year ended 31 December 2024 were payable by the Group to Deloitte:
Year ended 31 December 2025 Year ended
$'000 31 December 2024
$'000
Fees payable to the Company's auditor for the audit of the parent company and 1,476 1,367
Group financial statements
The audit of the Company's subsidiaries 303 173
Total audit 1,779 1,540
Audit-related assurance services(i) 694 589
Total audit and audit-related assurance services 2,473 2,129
Total auditor's remuneration 2,473 2,129
(i) Audit-related assurance services in both years primarily include the
review of the Group's interim results, G&A assurance review and the
provision of customary comfort letters in respect of the Group's refinancing
activities. Included within 2025 is £30,000 (2024: nil) related to other
services that are not assurance related
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 2025 Year ended
$'000 31 December 2024
$'000
Finance costs:
Loan interest payable 6,027 18,524
Bond interest payable 69,269 54,971
Unwinding of discount on decommissioning provisions (see note 22) 35,912 30,290
Unwinding of discount on other provisions (see note 22) 755 911
Debt refinancing fees (see note 17) - 4,809
Finance charges payable under leases (see note 23) 25,100 27,673
Finance fees on loans and bonds including amortisation of capitalised fees 15,337 14,473
Other financial expenses 12,191 7,771
Total finance costs 164,591 159,422
Finance income:
Bank interest receivable 6,535 11,110
RockRose loan interest (see note 18(f)) 2,639 3,263
Other financial income 50 135
Total finance income 9,224 14,508
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.
The Group has applied the mandatory exception to recognising and disclosing
information about the deferred tax assets and liabilities relating 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.
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 2030. 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 2025 Year ended
$'000 31 December 2024
$'000
Current UK income tax
Current income tax charge 1,051 -
Current overseas income tax
Current income tax charge 12,351 11,432
Adjustments in respect of current income tax of previous years 307 (746)
UK Energy Profits Levy
Current year charge 84,069 10,262
Adjustments in respect of current charge of previous years((i)) 19,378 (8,803)
Total current income tax 117,156 12,145
Deferred UK income tax
Relating to origination and reversal of temporary differences 222,897 42,745
Adjustments in respect of deferred income tax of previous years((i)) 12,209 (9,103)
Deferred overseas income tax
Relating to origination and reversal of temporary differences 7,581 7,071
Adjustments in respect of deferred income tax of previous years (363) 31
Deferred UK Energy Profits Levy
Relating to origination and reversal of temporary differences 134,985 11,156
Adjustments in respect of changes in tax rates - 6,889
Adjustments in respect of deferred charge of previous years (2,600) 1,907
Total deferred income tax 374,709 60,696
Income tax expense reported in profit or loss 491,865 72,841
(i) Adjustments in respect of previous years arose upon finalisation of
various UK tax returns and include an additional EPL current tax liability of
$19.4 million and an additional deferred tax liability of $7.8 million. These
adjustments reflect corrections to the amount of tax relief accrued in the
2024 financial year end group tax position arising as a result of
reclassifications made during that year from inventory to property, plant and
equipment as part of a review of well supplies
(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
2025 2024
$'000 $'000
Profit/(loss) before tax 493,427 166,614
UK statutory tax rate applying to North Sea oil and gas activities of 40% 197,371 66,646
(2024: 40%)
Supplementary corporation tax non-deductible expenditure 4,383 5,809
Non-deductible expenditure(i) 8,537 26,114
Non-taxable gain on sale of assets - 505
Petroleum revenue tax (net of income tax benefit) (363) (8,938)
Tax in respect of non-ring-fence trade 13,776 7,298
Deferred tax asset not recognised in respect of non-ring-fence trade 21,426 12,243
Deferred tax asset recognised on previously unrecognised losses - (48,115)
UK Energy Profits Levy(ii) 95,179 (13,921)
UK Energy Profits Levy - changes in tax rates(iii) - 6,889
UK Energy Profits Levy - abolishment of Investment Allowance(iii) - 35,339
UK Energy Profits Levy - extension to March 2030(iv) 123,875 -
Adjustments in respect of prior years 28,931 (16,713)
Overseas tax rate differences (1,323) 2,045
Share-based payments (132) (1,407)
Other differences 205 (953)
At the effective income tax rate of 100% (2024: 44%) 491,865 72,841
(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) This consists of an Energy Profits Levy current tax charge of $84.1
million (2024: $10.3 million) and deferred Energy Profits Levy charge of $11.1
million (2024: $18.0 million).The 2025 charge was impacted by the higher rate
of 38% which applied from 1 November 2024 (period to 31 October 2024: 35%)
and the removal of investment allowances
(iii) Refers to the impact of the increased rate and removal of investment
allowances that were substantially enacted in 2024
(iv) Reflects the impact of the substantively enacted two-year extension
referred to in part (e) below
(c) Deferred income tax
Deferred income tax relates to the following:
Group balance sheet Charge/(credit) for the year recognised in profit or loss
2025 2024 2025 2024
$'000 $'000 $'000 $'000
Deferred tax liability
Accelerated capital allowances 1,039,396 911,501 126,945 33,701
1,039,396 911,501
Deferred tax asset
Losses (627,124) (717,900) 90,777 (22,012)
Decommissioning liability (296,069) (263,705) (33,047) 2,095
Other temporary differences((i)) (137,214) (331,679) 190,034 46,912
(1,060,407) (1,313,284) 374,709 60,696
Net deferred tax (assets)((ii)) (21,011) (401,783)
Reflected in the balance sheet as follows:
Deferred tax assets (271,375) (506,481)
Deferred tax liabilities 250,364 104,698
Net deferred tax (assets) (21,011) (401,783)
(i) Predominantly includes $107.7 million on deferred income in note 24 and
$17.5 million Petroleum Revenue Tax refunds
(ii)The total amounts for EPL included in net deferred assets are $276.3
million for accelerated capital allowances offset by $56.7 million for other
items, which predominantly includes $52.5 million related to deferred income
(note 24)
Reconciliation of net deferred tax assets/(liabilities)
2025 2024
$'000 $'000
At 1 January 401,783 462,479
Tax expense during the period recognised in profit or loss (374,709) (60,696)
Deferred taxes acquired in business combinations (see note 30) (6,063) -
At 31 December 21,011 401,783
(d) Tax losses
The Group's deferred tax assets at 31 December 2025 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). The Group is currently
recognising all UK tax losses (with the exception of those noted below) and
neither a 10% increase or 10% decrease in oil price would result in any change
to the full recognition.
The Group has unused UK mainstream corporation tax losses of $578.4 million
(2024: $496.1 million) and ring-fence tax losses of $1,117.5 million (2024:
$1,117.5 million) associated with EnQuest Progress Limited, for which no
deferred tax asset has been recognised at the balance sheet date as recovery
of these losses is to be established. In addition, the Group has not
recognised a deferred tax asset for the adjustment to bond valuations on the
adoption of IFRS 9. The benefit of this deduction is taken over ten years,
with a deduction of $2.2 million being taken in the current period and the
remaining benefit of $4.2 million (2024: $6.3 million) remaining unrecognised.
The Group has unused Malaysian income tax losses of $16.3 million (2024: $14.7
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
On 29 July 2024, the UK Government announced various changes to the EPL
including an extension to 31 March 2030 (previously 31 March 2028) to which
the EPL applies. This extension was substantively enacted on 3 March 2025,
with the impact on the current period financial statements tax charge and
deferred tax for EPL being $123.9 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.
At 31 December 2025, the Group held 20,000,000 Ordinary shares (2024:
25,000,000 Ordinary shares) which were classified in the balance sheet as
Treasury shares. The Treasury shares have been excluded for the purposes of
calculating the basic and diluted earnings per share at 31 December 2025.
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
2025 2024 2025 2024 2025 2024
$'000 $'000 million million $ $
Basic 1,562 93,773 1,859.9 1,891.9 0.001 0.050
Dilutive potential of Ordinary shares granted under share-based incentive
schemes
- - 24.2 24.3 - (0.001)
Diluted 1,562 93,773 1,884.1 1,916.2 0.001 0.049
8. Distributions paid and proposed
The Company paid dividends of 0.616 pence per share during the year ended 31
December 2025 (2024: none).
Following the successful implementation of its capital discipline strategy,
EnQuest remains committed to delivering sustainable shareholder returns.
Building on the inaugural dividend paid last year, the Board is pleased to
propose a second final ordinary dividend of 0.801 pence per share (equivalent
to approximately $20.0 million). This proposed dividend is subject to approval
by shareholders at the Annual General Meeting scheduled for 22 May 2026, and
accordingly has not been recognised as a liability as at 31 December 2025. If
approved, the dividend will be paid on 5 June 2026 to shareholders on the
register at 8 May 2026, with shares trading ex-dividend from 7 May 2026.
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 and Vietnam FPSOs which are 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 2024 9,243,807 68,578 904,994 10,217,379
Additions 325,813 394 16,453 342,660
Change in decommissioning provision (741) - - (741)
At 1 January 2025 9,568,879 68,972 921,447 10,559,298
Additions 176,552 277 32,302 209,131
Acquisition (see note 30) 24,716 - 33,002 57,718
Disposals (1,672) - (37,881) (39,553)
Change in decommissioning provision (note 22) 77,862 - - 77,862
At 31 December 2025 9,846,337 69,249 948,870 10,864,456
Accumulated depreciation, depletion and impairment:
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 1 January 2025 7,651,364 61,997 547,983 8,261,344
Charge for the year 211,616 1,628 59,184 272,428
Net impairment (reversal)/charge for the year 23,019 - (28,838) (5,819)
Disposal - - (33,628) (33,628)
At 31 December 2025 7,885,999 63,625 544,701 8,494,325
Net carrying amount:
At 31 December 2025 1,960,338 5,624 404,169 2,370,131
At 31 December 2024 1,917,515 6,975 373,464 2,297,954
At 1 January 2024 1,879,744 9,264 407,732 2,296,740
The amount of borrowing costs capitalised during the year ended 31 December
2025 was nil (2024: nil), reflecting the short-term nature of the Group's
capital expenditure programmes.
Impairments
Impairments to the Group's producing assets and reversals of impairments are
set out in the table below:
Impairment Recoverable
reversal/(charge) amount(i)
Year ended 31 December 2025 Year ended 31 December 2024
$'000 $'000 31 December 2025 31 December 2024
$'000 $'000
North Sea 5,819 (71,414) 1,100,312 1,172,487
Net pre-tax impairment reversal/(charge) 5,819 (71,414)
(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 2025 net impairment reversal of $5.8 million relates to producing assets
in the UK North Sea (an impairment reversal of $94.3 million at Kraken offset
by charges of $33.5 million for GKA and Scolty/Crathes CGU, $43.5 million for
Golden Eagle and $11.5 million for Alba). Impairment reversals/charges were
primarily driven by a combination of lower discount rate, changes in
production and cost profiles, including the impact of weaker USD, and lower
near-term oil price assumptions.
The 2024 net impairment charge of $71.4 million related 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.
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:
2025 2024
$'000 $'000
Cost and net carrying amount
At 1 January 134,400 134,400
Acquisition (see note 30) 5,110 -
At 31 December 139,510 134,400
The majority of the goodwill relates to the 75% acquisition of the Magnus oil
field and associated interests. The remaining opening balance relates to the
acquisition of the GKA and Scolty Crathes fields. During 2025, the Group
acquired Block 12W in Vietnam (see note 30) resulting in goodwill recognised
of $5.1 million.
Impairment testing of goodwill
Goodwill, which has been acquired through business combinations, has been
allocated as appropriate to the UK North Sea segment grouping of CGUs and the
Vietnam CGU, and these are 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), while the Vietnam CGU relates
to the Block 12W asset.
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 2025 (2024: nil) based on a
fair value less costs to dispose valuation of the 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 reasonably
possible change for the purposes of sensitivity analysis (see note 2). A 10%
reduction in oil price would result in an impairment charge of $70.7 million
(2024: 10% reduction would result in an impairment charge of $66.7 million). A
15% reduction in oil price would fully impair goodwill (2024: 17%), however
Management do not consider this to be a reasonably possible change.
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 2025, there was no impairment of historical
exploration and appraisal expenditures (2024: nil).
Other intangibles
UK emissions allowances ('UKAs') purchased to settle the Group's liability
related to emissions are recognised on the balance sheet as an intangible
asset at cost. The UKAs will be derecognised upon settling the liability with
the respective regulator.
Exploration and appraisal assets UK emissions allowances $'000 Total
$'000 $'000
Cost:
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 1 January 2025 129,716 1,138 130,854
Additions 4,225 6,472 10,697
Write-off of relinquished licence (173) - (173)
Disposal - (6,500) (6,500)
At 31 December 2025 133,768 1,110 134,878
Accumulated impairment:
At 1 January 2024, 1 January 2025 and 31 December 2025 (109,153) - (109,153)
Net carrying amount:
At 31 December 2025 24,615 1,110 25,725
At 31 December 2024 20,563 1,138 21,701
At 1 January 2024 18,323 876 19,199
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.
2025 2024
$'000 $'000
Hydrocarbon inventories 8,487 22,544
Well supplies 24,272 26,432
32,759 48,976
During 2025, a net charge of $16.9 million was recognised within cost of sales
in the Group income statement relating to inventory, reflecting additional
sales related to Magnus hydrocarbon stock (2024: net gain of $6.9 million).
The inventory valuation at 31 December 2025 is stated net of a provision of
$22.5 million (2024: $28.5 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.
2025 2024
$'000 $'000
Available cash 265,886 226,317
Restricted cash 2,960 53,922
Cash and cash equivalents 268,846 280,239
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
Restricted cash at 31 December 2025 includes a residual $1.2 million in
accounts relating to 2025 decommissioning security agreement obligations (31
December 2024: $53.4 million). The remaining $1.8 million of restricted cash
relates to a Performance Bond in Indonesia (31 December 2024: $0.5 million
related to bank guarantees for the Group's Malaysian assets).
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 2025 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
Commodity contracts 18(a) 36,754 36,754 - 36,754 -
Forward foreign currency contracts 18(a) 932 932 - 932 -
Forward UKA contracts 18(a) 28,721 28,721 - 28,721 -
Other financial assets measured at FVPL -
Quoted equity shares 6 6 6 - -
Total financial assets measured at fair value 66,413 66,413 6 66,407 -
Financial assets measured at amortised cost:
Vendor financing facility 18(f) 43,896 43,896 - 43,896 -
Total financial assets measured at amortised cost((i)) 43,896 43,896 - 43,896 -
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Commodity contracts 18(a) 1,997 1,997 - 1,997 -
Forward UKA contracts 18(a) 8,394 8,394 - 8,394 -
Other financial liabilities measured at FVPL
Contingent consideration 21 84,620 84,620 - - 84,620
Total liabilities measured at fair value 95,011 95,011 - 10,391 84,620
Liabilities measured at amortised cost
Interest-bearing loans and borrowings((i)) 17 60,324 60,324 - 60,324 -
GBP retail bond 9.00%((ii)) 17 181,812 180,892 180,892 - -
USD high yield bond 11.625%((ii)) 17 465,328 470,878 470,878 - -
Total liabilities measured at amortised cost((iii)) 707,464 712,094 651,770 60,324 -
((i)) Amortised cost is a reasonable approximation of the fair value, carrying
value includes accrued interest
((ii)) Carrying value includes accrued interest and related fees
((iii)) Amounts included in the Total column, exclude related fees
31 December 2024 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) 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 -
GBP retail bond 9.00%((ii)) 17 169,371 161,461 161,461 - -
USD 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, carrying
value includes accrued interest
((ii)) Carrying value includes accrued interest and related fees
((iii)) Amounts included in the Total column, exclude 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 (2024: 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 2). A reconciliation of
movements is disclosed in note 29.
15. Trade and other receivables
2025 2024
$'000 $'000
Current
Trade receivables 15,357 20,151
Joint venture receivables 104,608 106,963
Under-lift position 18,073 16,806
VAT receivable 12,377 7,574
Vietnam lease receivable from joint venture partners 5,122 -
Other receivables((i)) 55,015 25,989
Prepayments 13,821 5,720
Accrued income 21,096 47,768
Total current 245,469 230,971
Non-current
Vietnam abandonment fund 92,079 -
Vietnam lease receivable from joint venture partners 19,473 -
Other receivables 16,614 2,102
Total non-current 128,166 2,102
((i)) Predominantly relates to amounts charged to SVT owners and users
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 2025 or 2024.
Non-current receivables mainly comprise the Group's share of cash
contributions made into an abandonment fund which was established to ensure
that sufficient funds exist to meet future abandonment obligations on Block
12W in Vietnam. The funds are maintained in a bank account by PetroVietnam and
the joint venture partners retain the legal rights and obligations to all
monies contributed to the abandonment funds, pending commencement of
abandonment operations.
The lease receivable relates to the Group's lease of an FPSO used on Block 12W
in Vietnam. The related liability is recorded on a gross basis as EnQuest is
the sole signatory to the lease, with joint venture partners providing a
parent company guarantee with respect to their share of the lease liability.
The Group's share of this liability is recorded as a right of use asset (see
note 23) with the remainder, representing the share of future payments to be
reimbursed by the other partners in Block 12W in Vietnam, recorded as an
"other receivable" split between current and non-current based on the expected
timing of reimbursement by the partners.
Other non-current receivables represents capitalised fees associated with the
Group's Reserve Based Lending Facility disclosed within trade and other
receivables to better reflect the variable nature of drawings under the
facility.
16. Trade and other payables
2025 2024
$'000 $'000
Current
Trade payables 124,806 138,822
Accrued expenses 287,408 209,225
Over-lift position 8,136 16,849
Joint venture creditors 25,750 46,187
Other payables 8,550 3,307
Total current 454,650 414,390
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 ten and 30 days.
Accrued expenses include accruals for capital and operating expenditure in
relation to the oil and gas assets and interest accruals.
17. Loans and borrowings
2025 2024
$'000 $'000
Loans 60,324 33,972
Bonds 647,140 630,885
707,464 664,857
The Group's borrowings are carried at amortised cost as follows:
2025 2024
Principal $'000 Fees Total Principal Fees Total
$'000
$'000 $'000 $'000 $'000
SVT working capital facility 36,331 - 36,331 33,972 - 33,972
Vendor loan facility 22,096 - 22,096 - - -
USD high yield bond 11.625% 465,000 (6,156) 458,844 465,000 (10,661) 454,339
GBP retail bond 9.00% (GBP 133.3 million) 179,367 - 179,367 167,101 - 167,101
Accrued interest((i)) 10,826 - 10,826 9,445 - 9,445
Total borrowings 713,620 (6,156) 707,464 675,518 (10,661) 664,857
Due within one year 69,253 43,417
Due after more than one year 638,211 621,440
Total borrowings 707,464 664,857
((i)) Accrued interest includes vendor loan facility interest accruals of $1.9
million (2024: $nil) and bond interest accruals of $8.9 million (2024: $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 November 2025, the Group agreed a new six-year Senior Secured Reserves
Based Lending ('RBL') facility totalling $800.0 million comprising a $400.0
million multi-currency revolving loan facility, $400.0 million multi-currency
revolving letter of credit facility and an accordion of up to $800.0 million
which, although uncommitted, provides the potential to extend the secured
revolving loan facility and the revolving letter of credit facility by up to
$400.0 million each. The maturity of the facility is December 2031. Funds can
only be drawn under the loan facility to a maximum amount of the lesser of:
(i) the total commitments; and (ii) the borrowing base amount. Interest
accrues at 4.00%, plus a combination of an agreed credit adjustment spread and
the Secured Overnight Financing Rate ('SOFR'). The facility replaced the
Group's previous reserves based lending facility, which was signed in October
2022 and accrued interest at 4.50%, plus a combination of an agreed credit
adjustment spread and the SOFR.
Fees associated with the new RBL of $20.4 million were capitalised within
trade and other receivables (note 15) and are being amortised over the period
of the facility on a straight-line basis. The remaining unamortised fees
relating to the previous RBL of $2.4 million were expensed within finance
costs.
At 31 December 2025, there were no loan drawdowns under the RBL (2024: $nil),
with $400.0 million remaining available for drawdown (2024: $176.4 million).
At 31 December 2025, Letter of Credit utilisation was $381.5 million (2024:
$54.1 million). The increased utilisation of Letters of Credit reflected their
use in providing security under the Group's decommissioning security
obligations, replacing the Group's prior period's use of surety bonds and
cash.
SVT working capital facility
In 2024, EnQuest 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 based on certain qualifying
invoices that EnQuest has paid up to an amount of £23.7 million, with
interest payable monthly at a rate of 9.50% per annum. At 31 December 2025,
$22.1 million had been drawn down on the facility (2024: $nil).
US Dollar 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.
The above carrying value of the bond as at 31 December 2025 is $458.8 million
(2024: $454.3 million). This includes bond principal of $465.0 million (2024:
$465.0 million) and unamortised issue premium on the tap of $1.0 million
(2024: $1.4 million) less the unamortised original issue discount of $1.5
million (2024: $2.4 million) and unamortised fees of $5.8 million (2024: $9.7
million). The fair value of the US Dollar high yield bond is disclosed in note
14.
GBP retail bond 9.00%
On 27 April 2022, the Group issued a new 9.00% GBP retail bond following a
successful partial exchange and cash offer. The principal of the GBP 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 2025 is $179.4 million
(2024: $167.1 million). All fees associated with this offer were recognised in
the income statement in 2022. The fair value of the GBP retail bond 9.00% is
disclosed in note 14.
18. Other financial assets and financial liabilities
(a) Summary as at year end
2025 2024
Assets Liabilities $'000 Assets Liabilities $'000
$'000
$'000
Fair value through profit or loss:
Derivative commodity contracts 35,009 1,997 69 10,497
Forward foreign currency contracts 932 - - 2,354
Derivative UKA contracts 23,550 8,394 - 8,729
Total current 59,491 10,391 69 21,580
Fair value through profit or loss:
Derivative commodity contracts 1,745 - - -
Derivative UKA contracts 5,171 - - -
Quoted equity shares 6 - 6 -
Amortised cost:
Other receivables (Vendor financing facility) (notes 18(f), 24) 43,896 - 38,453 -
Total non-current 50,818 - 38,459 -
Total other financial assets and liabilities 110,309 10,391 38,528 21,580
(b) Income statement impact
The income/(expense) recognised for derivatives are as follows:
Year ended 31 December 2025 Revenue and other operating income Cost of
sales
Realised $'000 Unrealised $'000 Realised $'000 Unrealised $'000
Commodity options (6,561) 7,766 - -
Commodity swaps 15,567 37,225 - -
Commodity futures (262) 187 - -
Foreign exchange contracts - - 20,766 3,286
UKA contracts - - (1,055) 29,056
8,744 45,178 19,711 32,342
Year ended 31 December 2024 Revenue and other operating income Cost of
sales
Realised Unrealised $'000 Realised Unrealised $'000
$'000 $'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)
(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 2025, gains totalling $53.9 million (2024:
losses of $9.8 million) were recognised in respect of commodity contracts
measured as FVPL. This included gains totalling $8.7 million (2024: losses of
$12.9 million) realised on contracts that matured during the year, and
mark-to-market unrealised gains totalling $45.2 million (2024: gains of $3.1
million).
The mark-to-market value of the Group's open commodity contracts as at 31
December 2025 was a net asset of $34.8 million (2024: net liability of $10.4
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 2025, gains totalling
$24.1 million (2025: gains of $0.5 million) were recognised in the Group
income statement. This included realised gains totalling $20.8 million (2024:
gains 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 2025
was a net asset of $0.9 million (2024: net liability of $2.4 million).
(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
2025, gains totalling $28.0 million (2024: losses of $8.1 million) were
recognised in the Group income statement. This included realised losses
totalling $1.1 million (2024: losses of $7.6 million) on contracts that
matured in the year.
The mark-to-market value of the Group's open contracts as at 31 December 2025
was a net asset of $20.3 million (2024: net liability of $8.7 million).
(f) Other receivables
Other receivables
$'000 Equity shares Total
$'000 $'000
At 1 January 2024 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
Interest 2,639 - 2,639
Foreign Exchange 2,804 - 2,804
At 31 December 2025 43,896 6 43,902
Current -
Non-current 43,902
43,902
Other receivables 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 2025 1,885,029,503 131,508 260,546 (4,425) 2,006 389,635
Shares transferred to EBT - - - 885 - 885
At 31 December 2025 1,885,029,503 131,508 260,546 (3,540) 2,006 390,520
At 31 December 2025, 20,000,000 (2024: 25,000,000) Ordinary shares were 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. During the year, 5,000,000 shares were transferred to
the Company's EBT.
At 31 December 2025, there were 3,948,076 shares held by the EBT (2024:
972,269) which are included within the share-based payment reserve. The
movement in the year was 2,975,807 shares used to satisfy awards made under
the Company's share-based incentive schemes offset by a transfer of shares
from Treasury.
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 (income)/expense recognised for each scheme was as
follows:
2025 2024
$'000 $'000
Performance Share Plan (806) 511
Other performance share plans (8) 64
Sharesave Plan 145 408
(669) 983
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 2025 2024
Number Number
Outstanding at 1 January 88,617,683 87,367,455
Granted during the year 27,138,555 35,353,664
Exercised during the year (1,493,821) (7,291,023)
Forfeited during the year (17,282,431) (26,812,413)
Outstanding at 31 December 96,979,986 88,617,683
Exercisable at 31 December 15,172,474 9,138,271
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 2025 2024
Number Weighted average exercise price $ Number Weighted average exercise price
$
Outstanding at 1 January 9,956,017 0.15 18,658,144 0.16
Exercised during the year - - (5,478,693) 0.13
Forfeited during the year (1,575,108) 0.21 (3,223,434) 0.15
Outstanding at 31 December 8,380,909 0.15 9,956,017 0.15
Exercisable at 31 December 155,925 0.28 323,886 0.24
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 charge 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 2024 451,333 21,961 473,294
Unwinding of discount (see note 4(d)) 51,002 2,645 53,647
Other change in fair value (see note 4(d)) (442,335) 1,543 (440,792)
Utilisation - (1,529) (1,529)
At 31 December 2025 60,000 24,620 84,620
Classified as:
Current 60,000 318 60,318
Non-current - 24,302 24,302
60,000 24,620 84,620
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.
In February 2026, an agreement was concluded with bp for EnQuest to settle the
profit share arrangement for $60.0 million, with payment made the same month.
As the agreement was substantially agreed at 31 December 2025, this value has
been used to fair value the contingent consideration which resulted in a
decrease in fair value (excluding the impact of unwind of discount) of $442.3
million (2024: decrease of $43.4 million). The decrease in 2024 reflected a
reduction in the Group's near-term oil price assumptions and changes in the
assets cost and production profile. The overall fair value accounting effect
relating to the contingent consideration, including the unwinding of discount,
totalled income of $391.3 million (2024: charge of $11.8 million) which was
recognised in the Group income statement. Within the statement of cash flows,
the profit share element of the repayment is disclosed separately under
investing activities. There were no profit share payments during the year
(2024: $48.5 million). At 31 December 2025, the contingent consideration for
Magnus was $60.0 million (31 December 2024: $451.3 million).
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
2025, the amount due to bp calculated on an after-tax basis by reference to
30% of bp's decommissioning costs on Magnus was $24.6 million (2024: $22.0
million). Any reasonably possible change in assumptions would not have a
material impact on the provision.
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 2024 741,565 18,348 6,193 766,106
Acquisition (see note 30) 89,052 - - 89,052
Additions during the year(i) 46,721 - 461 47,182
Changes in estimates(i) 40,868 4,772 (5,083) 40,557
Unwinding of discount 35,912 755 - 36,667
Utilisation(ii) (38,486) (8,589) (481) (47,556)
Foreign exchange - - 28 28
At 31 December 2025 915,632 15,286 1,118 932,036
Classified as:
Current 48,853 4,915 314 54,082
Non-current 866,779 10,371 804 877,954
915,632 15,286 1,118 932,036
(i) Includes $77.9 million related to producing assets disclosed in note 9 and
$9.7 million relating to assets in decommissioning disclosed in note 4(d)
(ii) Utilisation differs to amounts paid in the cash flow statement due to
movements in accruals recognised within trade and other payables
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. The Group's decommissioning provision has
increased by $174.0 million in the period. This primarily reflects the
discounted decommissioning liability acquired as part of the Vietnam asset
acquisition of $89.1 million (which is largely pre-funded as set out below),
additional liability recognised in relation to Seligi Non-Associated Gas
rights in Malaysia of $41.5 million and higher cost estimates of $40.9
million, predominantly due to a weaker US Dollar, offset partly by the ongoing
decommissioning programmes utilisation of $38.5 million.
At 31 December 2025, an estimated $364.3 million is expected to be utilised
between one and five years (2024: $281.1 million), $373.1 million within six
to ten years (2024: $280.0 million), and the remainder in later periods. For
sensitivity analysis see Use of judgements, estimates and assumptions within
note 2.
The Vietnam PSC requires the expected decommissioning liability to be
pre-funded via a quarterly cash payment into an abandonment cess fund. The
balance of amounts previously deposited into the cess fund is held in escrow
to be drawn against when abandonment takes place. As at 31 December 2025,
EnQuest's share of the cess fund was $92.1 million and is disclosed in
non-current trade and other receivables (note 15).
The Group uses Letters of Credit, surety bonds and cash deposits to provide
security for its decommissioning obligations. Following the agreement of a new
RBL facility in November 2025, the Group utilised Letters of Credit totalling
$381.5 million to provide security for its decommissioning obligations at 31
December 2025 (2024: surety bonds totalling $277.0 million and cash deposits
of $53.4 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 2025, the amount
due to bp by reference to 7.5% of bp's decommissioning costs on Thistle and
Deveron was $15.3 million (2024: $18.3 million), with the reduction mainly
reflecting the utilisation in the period. Change in estimates of $4.8 million
are included within other expense (2024: $0.4 million) and unwinding of
discount of $0.8 million is included within finance costs (2024: $0.9
million).
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. 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 sole signatory
and the only party with the legal obligation to make lease payments to the
lessor but the joint venture partners provide guarantees in relation to their
share of the liability, the full lease liability will be recognised, along
with the Group's share of the right-of-use asset and a receivable balance
representing amounts owed by joint venture partners. 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 2023 407,732 422,174
Additions in the period 16,453 16,453
Depreciation expense (54,735) -
Impairment reversal 4,014 -
Interest expense - 27,673
Payments - (130,065)
Foreign exchange movements - (980)
As at 31 December 2024 373,464 335,255
Acquisition (see note 30) 33,002 60,681
Additions in the period (see note 9) 32,302 32,302
Depreciation expense (see note 9) (59,184) -
Impairment reversal (see note 9) 28,838 -
Interest expense - 25,100
Payments - (83,061)
Foreign exchange movements - 5,818
Disposal (4,253) (4,005)
As at 31 December 2025 404,169 372,090
Current 86,323
Non-current 285,767
372,090
The carrying value of the right-of-use assets include $373.9 million (2024:
$340.9 million) of oil and gas assets and $30.3 million (2024: $32.6 million)
of buildings.
The Group leases assets, including the Kraken and Vietnam FPSOs, property, and
oil and gas vessels, with a weighted average lease term of three years. The
maturity analysis of lease liabilities is disclosed in note 27.
Amounts recognised in profit or loss
Year ended 31 December 2025 Year ended
$'000 31 December 2024
$'000
Depreciation expense of right-of-use assets 59,184 54,735
Impairment reversal of right-of-use assets (28,838) (4,014)
Interest expense on lease liabilities 25,100 27,673
Rent expense - short-term leases 9,018 13,860
Rent expense - leases of low-value assets 297 33
Total amounts recognised in profit or loss 64,761 92,287
Amounts recognised in statement of cash flows
Year ended 31 December 2025 Year ended 31 December 2024
$'000 $'000
Total cash outflow for leases 83,061 130,065
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 2025
was $1.9 million (2024: $2.2 million).
The following table sets out a maturity analysis of the lessees lease payments
to EnQuest as lessor, showing the undiscounted lease payments to be received
after the reporting date:
2025 2024
$'000 $'000
Less than one year 1,291 2,029
One to two years 1,293 858
Two to three years 1,310 860
Three to four years 1,317 875
Four to five years 821 882
More than five years 1,326 1,856
Total undiscounted lease payments 7,358 7,360
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 2025 Year ended 31 December 2024
$'000 $'000
Deferred income 138,095 138,095
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 2025, the Group had commitments for future capital expenditure
amounting to $48.4 million (2024: $13.3 million). The increase primarily
relates to commitments for the development of the non-associated gas resources
in the PM8/Seligi PSC contract area under the Seligi 1b gas agreement. The key
remaining components of this relate to minimum work commitments in Indonesia
and Brunei. 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 2025, the Group utilised Letters of
Credit totalling $381.5 million under its new RBL facility to provide security
for its decommissioning obligations, having held surety bonds totalling $277.0
million in 2024. 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. For example, in 2025, the NSTA
engaged with EnQuest with regards to the timing/scheduling of certain plug and
abandon obligations, which remain under discussion. Regardless, 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 2025 (2024: none).
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.
2025 2024
$'000 $'000
Short-term employee benefits 5,206 5,138
Share-based payments 30 124
Post-employment pension benefits 278 226
Termination payments 133 947
5,647 6,435
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
2025, 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 2025 and 2024, 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 production based on the proportion of the loan facility utilised. Where
the relevant amounts utilised are 10% or less of the amounts available, the
Group is required to hedge a minimum of 10% of volumes of net entitlement
production expected in the next 12 months and the following 12 months. Where
the relevant amounts utilised are more than 10% but less than 50% of the
amounts available, the Group is required to hedge a minimum of 30% of volumes
of net entitlement production expected in the next 12 months and a minimum of
15% of volumes of net entitlement production expected in the following 12
months. Where the relevant amounts utilised are 50% or more of the amounts
available, the Group is required to hedge a minimum of 45% of volumes of net
entitlement production expected in the next 12 months and a minimum of 30% of
volumes of net entitlement production expected in the following 12 months.
Details of the commodity derivative contracts entered into during and open at
the end of 2025 are disclosed in note 18. As of 31 December 2025, the Group
held financial instruments (options and swaps) related to crude oil that
covered 3.4 MMbbls of 2026 production and 0.9 MMbbls of 2027 production. The
instruments have an effective average floor price of around $68.3/bbl in 2026
and $63.5/bbl in 2027. 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 2025.
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 2025 (42,600) 42,900
31 December 2024 (47,600) 47,200
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, the 9.00% retail bond,
the vendor financing facility and any UK EPL cash tax payments which are
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 17% (2024: 12%)
of the Group's sales and 98% (2024: 97%) 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 2025 GBP MYR Other Total
$'000 $'000 $'000 $'000
Total financial assets 357,349 30,762 12,015 400,126
Total financial liabilities 783,464 28,336 13,364 825,164
Year ended 31 December 2024 GBP MYR Other Total
$'000 $'000 $'000 $'000
Total financial assets 396,168 22,570 3,024 421,762
Total financial liabilities 714,626 21,731 3,801 740,158
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 2025 (22,189) 22,189
31 December 2024 (28,263) 28,263
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 2025, there were no trade receivables past due
but not impaired (2024: nil) and no joint venture receivables past due but not
impaired (2024: 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.
At 31 December 2025, the Group had one customer accounting for 65% of
outstanding trade receivables (2024: two customers, 91%) and four joint
venture partners accounting for over 75% of outstanding joint venture
receivables (2024: four partners, over 70%).
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 2025,
$409.8 million (2024: $194.3 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.
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 2025 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 - 60,888 - - - 60,888
Bonds - 69,945 714,312 - - 784,257
Contingent consideration - 60,335 6,681 1,382 65,571 133,969
Obligations under lease liabilities - 97,363 231,189 59,547 26,328 414,427
Trade and other payables - 446,527 - - - 446,527
- 735,058 952,182 60,929 91,899 1,840,068
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 - 397,543 - - - 397,543
- 587,573 205,572 1,189,144 456,723 2,439,012
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 2025 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 - 2,563 66 - - 2,629
Other derivative contracts - 43,411 7,485 22,015 - 72,911
- 45,974 7,551 22,015 - 75,540
Year ended 31 December 2024 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 - 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
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 (pages
12 to 16).
2025 2024
$'000 $'000
Loans, borrowings and bond(i) (A) (see note 17) 702,794 666,073
Cash and cash equivalents (see note 13) 268,846 (280,239)
EnQuest net debt (B) (ii) 433,948 385,834
Equity attributable to EnQuest PLC shareholders (C) 528,059 542,466
Profit/(loss) for the year attributable to EnQuest PLC shareholders (D) 1,562 93,773
Adjusted EBITDA (F) (ii) 503,823 673,919
Gross gearing ratio (A/C) 1.3 1.2
Net gearing ratio (B/C) 0.8 0.7
EnQuest net debt/adjusted EBITDA (B/F) (ii) 0.9 0.6
Shareholders' return on investment (D/C) 0.3% 17.3%
(i) Principal amounts drawn, excludes netting off of fees and accrued interest
(see note 17)
(ii) See Glossary - non GAAP measures on page 61
28. Subsidiaries
At 31 December 2025, 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 ENS Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Heather Leasing Limited(i) Dormant 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%
EnQuest Petroleum Developments Exploration, extraction and production of hydrocarbons Malaysia 100%
Malaysia SDN. BHD(i)3
EnQuest Advance Holdings Limited(i) Intermediate holding company England 100%
EnQuest Advance Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest Progress Limited(i) Exploration, extraction and production of hydrocarbons England 100%
North Sea (Golden Eagle) Resources Ltd(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%
Premier Oil (Vietnam) Limited(i)4 Exploration, extraction and production of hydrocarbons British Virgin Islands 100%
Premier Oil Vietnam Offshore B.V(i)5 Exploration, extraction and production of hydrocarbons Netherlands 100%
EnQuest EP Gaea Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest EP Gaea II Limited(i) Exploration, extraction and production of hydrocarbons England 100%
EnQuest EP BV Limited(i) Exploration, extraction and production of hydrocarbons England 100%
(i) Held by subsidiary undertaking
The Group has five branches outside the UK (all held by subsidiary
undertakings): EnQuest Global Services Limited (Dubai), EnQuest Global
Services Limited (Bahrain), EnQuest Petroleum Production Malaysia Limited
(Malaysia), Premier Oil Vietnam Offshore B.V (Vietnam) and EnQuest EP BV
Limited (Brunei).
In January 2026, EnQuest Group Holdings Limited was incorporated in England
and Wales as a holding company.
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 PO Box 3140, Road Town, Tortola, VG1110, British Virgin Islands
5 Lairessestraat 145 C,1075 HJ Amsterdam, the Netherlands
29. Cash flow information
Cash generated from operations
Notes Year ended 31 December 2025 Year ended
31 December 2024
$'000
$'000
Profit/(loss) before tax 493,427 166,614
Depreciation 4(c) 5,129 6,040
Depletion 4(b) 267,299 263,252
Exploration and appraisal expense 11 173 183
Net impairment (reversal)/charge to oil and gas assets 9 (5,819) 71,414
Net disposal/(write-back) of inventory 2,800 (5,539)
Share-based payment (credit)/charge 4(e) (669) 983
Change in Magnus related contingent consideration 21 (387,145) 15,904
Change in provisions 22 46,544 39,116
Other non-cash UKA losses 4(b) 11,490 1,335
Unrealised (gain)/loss on commodity financial instruments 4(a) (45,178) (3,090)
Unrealised (gain)/loss on other financial instruments 4(b) (32,342) 2,823
Unrealised exchange loss/(gain) 21,973 (8,714)
Net finance expense(i) 118,700 113,711
Operating cashflow before working capital changes 496,382 664,032
Decrease/(increase) in trade and other receivables 38,656 (4,561)
Decrease/(increase) in inventories 12,366 (5,786)
(Decrease)/increase in trade and other payables (49,585) 32,261
Cash generated from operations 497,819 685,946
(i) Excludes unwind of discount on provisions (see note 5)
Changes in liabilities arising from financing activities
Loans and borrowings $'000 Bonds Lease liabilities $'000 Total
$'000 $'000
At 1 January 2024 (311,210) (471,019) (422,174) (1,204,403)
Cash movements:
Repayments of loans and borrowings 312,304 - - 312,304
Proceeds from loans and borrowings (26,928) (160,000) - (186,928)
Payment of lease liabilities - - 130,065 130,065
Cash interest paid in year 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)
Cash movements:
Repayments of loans and borrowings((i)) 196,451 - - 196,451
Proceeds from loans and borrowings((ii)) (217,420) - - (217,420)
Payment of lease liabilities - - 83,061 83,061
Cash interest paid in year((iii)) 4,130 69,884 - 74,014
Non-cash movements:
Additions 20,448 - (32,302) (11,854)
Disposals - - 4,005 4,005
Acquired (see note 30) - - (60,681) (60,681)
Interest/finance charge payable (6,027) (69,269) (25,100) (100,396)
Fee amortisation (2,927) (4,505) - (7,432)
Foreign exchange and other non-cash movements (21,007) (12,365) (5,818) (39,190)
At 31 December 2025 (60,324) (647,140) (372,090) (1,079,554)
(i) Repayments of loans and borrowings include $120.0 million repaid under the
previous RBL facility, $70.0 million under the new RBL facility, and $6.5
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 balance of the previous RBL facility at the date of refinancing of
$50.0 million. This was fully repaid utilising the proceeds from the new
facility and as such is netted against the proceeds of the new RBL facility in
the Group Cash Flow Statement on the proceeds from loans and borrowings line
(ii) Proceeds from loans and borrowings include $120.0 million drawdown under
the previous RBL facility prior to refinancing and $70.0 million under new RBL
facility on refinancing, $6.7 million drawdowns under the SVT working capital
facility and $20.7 million under the vendor loan facility. In the Group Cash
Flow Statement, proceeds from loans and borrowings of $152.4 million include
amounts outlined in the table above less the previous RBL facility balance of
$50.0 million and associated new arrangement fees of $15.0 million. See note
17 for further details
(iii) The cash flow statement includes interest on decommissioning bonds,
Letters of Credit and the EPL
Reconciliation of carrying value
Loans Bonds Lease liabilities (see Total
(see (see note 23) $'000
note 17) note 17) $'000
$'000 $'000
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)
Principal (58,427) (644,367) (372,090) (1,074,884)
Unamortised fees - 6,156 - 6,156
Accrued interest (1,897) (8,929) - (10,826)
At 31 December 2025 (60,324) (647,140) (372,090) (1,079,554)
30. Business combination
Accounting policy
Business combinations are accounted for using the acquisition method. The cost
of an acquisition is measured as the aggregate of the consideration
transferred, which is measured at acquisition date fair value, and the amount
of any non-controlling interests in the acquiree. For each business
combination, the Group elects whether to measure the non-controlling interests
in the acquiree at fair value or at the proportionate share of the acquiree's
identifiable net assets. Acquisition-related costs are expensed as incurred
and included in administrative expenses. The Group determines that it has
acquired a business when the acquired set of activities and assets include an
input and a substantive process that together significantly contribute to the
ability to create outputs. The acquired process is considered substantive if
it is critical to the ability to continue producing outputs, and the inputs
acquired include an organised workforce with the necessary skills, knowledge,
or experience to perform that process or it significantly contributes to the
ability to continue producing outputs and is considered unique or scarce or
cannot be replaced without significant cost, effort, or delay in the ability
to continue producing outputs.
Acquisition of Block 12W Vietnam
The Group acquired a 53.125% interest in the Chim Sao and Dua fields ('Block
12W') in Vietnam from Harbour Energy on 9 July 2025 through acquisition of
100% of the share capital of two entities Premier Oil (Vietnam) Limited and
Premier Oil Vietnam Offshore BV.
The Group acquired this business as it represents a key step in delivering the
Group's diversified growth across South East Asia and aligns with its
strategic aim to expand its footprint by investing in fast-payback assets with
low capex and reduced carbon intensity. The Group acquired control through
payment of cash.
The Transaction assets constitute a business and the acquisition has been
accounted for using the acquisition method, in accordance with IFRS 3 Business
Combinations. The fair values and resulting goodwill are provisional and will
be finalised in EnQuest's half year 2026 financial statements.
The provisional fair values of the net identifiable assets as at the date of
acquisition are as follows:
Fair value recognised on acquisition
$'000
Note
Non-current assets
Property, plant and equipment 9 24,716
Right-of-use assets 9 33,002
Other receivables ((i)) 15 111,787
Current assets
Trade and other receivables 32,541
Taxation receivable 41
Cash and cash equivalents 5,850
Total assets 207,937
Non-current liabilities
Provisions((ii)) 22 89,052
Lease creditor((iii)) 23 44,845
Deferred tax 6 6,063
Current liabilities
Trade and other payables 30,546
Lease creditor((iii)) 23 15,836
Current tax liabilities 1,002
Total liabilities 187,344
Total identifiable net assets at fair value 20,593
Goodwill arising on acquisition 5,110
Purchase consideration transferred:
Cash transferred 25,703
Total consideration 25,703
(()(i)) (Represents) (EnQuest's share of a central abandonment fund of $91.2
million which will be used to pay for future abandonment of the Vietnam asset
and amounts owed by JV Partners of $20.6 million, with a further $7.1 million
shown within current receivables in respect of the lease liability associated
with the FPSO)
((ii) Represents a decommissioning liability)
((iii) Includes a lease liability predominantly in relation to the FPSO)
( )
$'000
Analysis of cash flows on acquisition
Total consideration 25,703
Net cash acquired with the subsidiaries (5,850)
Transaction costs of the acquisition 425
Net cash flow on acquisition 20,278
The goodwill has arisen primarily due to the requirement to recognise deferred
tax liabilities for the difference between the assigned fair values and the
tax bases of the acquired assets and liabilities assumed in a business
combination. The assessment of fair values of oil and gas assets acquired is
based on cash flows after tax. Nevertheless, in accordance with IAS 12 Income
Taxes, a provision is made for deferred tax corresponding to the tax rate
multiplied by the difference between the acquisition date fair value and the
tax base. The offsetting entry to this deferred tax is goodwill.
The acquisition date fair value of the trade receivables amounts to $0.3
million which is expected to be collected within contractual terms.
From the date of acquisition, the Transaction assets have contributed $52.8
million of revenue and $8.0 million to the profit before tax from continuing
operations of the Group. If the combination had taken place at the beginning
of the year, Group revenue from continuing operations would have been $1,162.9
million and the Group profit before tax from continuing operations would have
been $508.4 million.
31. Subsequent events
On 26 February 2026, EnQuest paid bp $60.0 million as final settlement of the
75% profit share contingent consideration liability, securing 100.0% of future
Magnus cash flows.
In February, EnQuest was notified by the Vietnam Ministry of Industry and
Trade that it had been successful in extending the Block 12W PSC by four years
to July 2034, on its existing terms. The PSC extension provides EnQuest and
its joint venture partners with the opportunity to access upside across Block
12W and progress discovered resources into reserves, with prospectivity spread
across three gas discoveries and several additional targets.
In February, EnQuest received a Letter of Award ('LOA') for a participating
interest in the Cendramas PSC by Petronas. The terms of the LOA, subject to
the finalisation and signing of the Joint Operating Agreement and the
Cendramas PSC, are effective from 23 September 2026.
The Group continues to monitor the situation in the Middle East following the
start of the conflict in February. At the date of this report, there has been
no material disruption to the Group's day-to-day business.
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.
The Group adjusts 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 2025 2024
$'000 $'000
Net profit/(loss) (A) 1,562 93,773
Adjustments - remeasurements and exceptional items :
Unrealised gains on derivative contracts (note 18) 77,520 267
Net impairment reversal/(charge) to oil and gas assets (note 9, note 10 and 5,819 (71,414)
note 11)
Change in contingent consideration (notes 4(d)) 387,145 (15,904)
Movement in other provisions (note 4(d)) 4,685 -
Insurance income on Kraken shutdown and PM8/Seligi riser incident (see note (53) 1,663
4(d))
Write-off of exploration costs (note 4(d)) (173) (183)
Business acquisition transaction costs (425) -
Other non-cash UKA losses (note 4(b)) (11,490) (1,335)
Drilling rig contract regret costs (note 4(d)) - (14,629)
Pre-tax remeasurements and exceptional items (B) 463,028 (101,535)
Tax on remeasurements and exceptional items (C) (347,506) 59,761
Post-tax remeasurements and exceptional items (D = B + C) 115,522 (41,774)
Adjusted net (loss)/ profit attributable to EnQuest PLC shareholders (A - D) (113,960) 135,547
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 2025 2024
$'000 $'000
Reported profit from operations before tax and finance income/(costs) 648,794 311,528
Adjustments:
Unrealised gains on derivative contracts (note 18) (77,520) (267)
Net impairment (reversal)/charge to oil and gas assets (note 9, note 10 and (5,819) 71,414
note 11)
Change in contingent consideration (notes 4(d)) (387,145) 15,904
Insurance income on Kraken and PM8/Seligi riser incident (see note 4(d)) 53 (1,663)
Licence write-off/write-off of exploration costs (see note 4(d)) 173 183
Drilling rig contract regret costs (see note 4(d)) - 14,629
Depletion and depreciation (note 4(b) and note 4(c)) 272,428 269,292
Inventory revaluation 2,800 (5,539)
Change in decommissioning and other provisions (note 4(d)) 9,814 7,078
Business combination transaction costs (note 30) 425 -
Other non-cash UKA losses (note 4(b)) 11,490 1,335
Net foreign exchange loss/(gain) (note 4(d)) 28,330 (9,975)
Adjusted EBITDA (E) 503,823 673,919
Total cash and available facilities is a measure of the Group's liquidity at
the end of the reporting period. The Group believes this is a useful metric as
it is an important reference point for the Group's going concern and viability
assessments, see pages 15 to 16.
Total cash and available facilities 2025 2024
$'000 $'000
Available cash 265,886 226,317
Restricted cash 2,960 53,922
Total cash and cash equivalents (F) (note 13) 268,846 280,239
Available undrawn facility (G)((ii)) 409,795 194,256
Total cash and available facilities (F + G) 678,641 474,495
((i))Includes amounts available under the RBL: $400.0 million (2024: $176.4
million) and vendor loan facility providing capacity for refinancing the
payment of existing invoices up to an amount of £23.7 million): $9.8 million
available (2024: $17.9 million)
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
pages 15 to 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 2025 2024
$'000 $'000
Loans and borrowings (note 17):
SVT working capital facility 36,331 33,972
Vendor loan facility 22,096 -
Bonds (note 17):
USD High yield bond 458,844 454,339
GBP Retail bond 179,367 167,101
Accrued interest 10,826 9,445
Loans and borrowings (H) 707,464 664,857
Non-cash accounting adjustments (note 17):
Unamortised fees on bonds 6,156 10,661
Accrued interest (10,826) (9,445)
Non-cash accounting adjustments (I) (4,670) 1,216
Debt (H + I) (J) 702,794 666,073
Less: Cash and cash equivalents (note 13) (F) 268,846 280,239
EnQuest net debt (J - F) (K) 433,948 385,834
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 2025 2024
$'000 $'000
EnQuest net debt (K) 433,948 385,834
Adjusted EBITDA (E) 503,823 673,919
EnQuest net debt/adjusted EBITDA (K/E) 0.9 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 2025 2024
$'000 $'000
Reported net cash flows (used in)/from investing activities (194,242) (182,435)
Adjustments:
Payment of Magnus contingent consideration - Profit share - 48,466
Proceeds from vendor financing facility receipt - (107,518)
Proceeds from Bressay farm-down - (1,263)
Acquisition 20,278 -
Interest received (5,286) (10,101)
Cash capital expenditure (179,250) (252,851)
Decommissioning expenditure (56,810) (60,544)
Cash capital and decommissioning expense (236,060) (313,395)
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 2025 2024
$'000 $'000
Net cash flows from/(used in) operating activities 362,725 507,631
Adjustments:
Purchase of property, plant and equipment (175,025) (249,165)
Purchase of oil and gas intangible assets (4,225) (3,686)
Payment of Magnus contingent consideration - (48,466)
Estimated cash tax on disposal proceeds((i)) - 50,000
Interest received 5,286 10,101
Payment of obligations under finance lease (83,061) (130,065)
Interest paid (96,997) (83,162)
Adjusted Free cash flow 8,703 53,188
((i)) Estimated by reference to disposal proceeds of $141.4 million and the
EPL tax rate at that time 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 2025 2024
$'000 $'000
Revenue from crude oil sales (note 4(a)) (L) 858,166 1,020,266
Revenue from gas and condensate sales (note 4(a)) 200,526 164,647
Realised gains/(losses) on oil derivative contracts (note 4(a)) (M) 8,744 (12,907)
Barrels equivalent sales 2025 2024
kboe kboe
Sales of crude oil (N) 12,595 12,554
Sales of gas and condensate(i) 2,678 2,400
Total sales 15,273 14,954
(i) Includes volumes related to onward sale of third-party gas purchases not
required for injection activities at Magnus
Average realised prices 2025 2024
$/Boe $/Boe
Average realised oil price, excluding hedging (L/N) 68.1 81.3
Average realised oil price, including hedging ((L + M)/N) 68.8 80.2
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 2025 2024
$'000 $'000
Total cost of sales (note 4(b)) 837,540 787,383
Adjustments:
Unrealised gains/(losses) on derivative contracts related to operating costs 32,342 (2,823)
(note 4(b))
Depletion of oil and gas assets (note 4(b)) (267,299) (263,251)
Charge relating to the Group's lifting position and inventory (note 4(b)) (17,407) (2,172)
Other cost of operations((i)) (note 4(b)) (179,628) (134,984)
Other non-cash UKA losses (11,490) (1,335)
Operating costs 394,058 382,818
Less: realised gains/(losses) on derivative contracts (P) (note 4(b)) 19,711 (4,735)
Operating costs directly attributable to production 413,769 378,083
Comprising of:
Production costs (Q) (note 4(b)) 344,580 307,634
Tariff and transportation expenses (R) (note 4(b)) 69,189 70,449
Operating costs directly attributable to production 413,769 378,083
(i) Includes $166.2 million (2024: $125.7 million) of purchases and associated
costs of third-party gas not required for injection activities at Magnus,
which is sold on
Barrels equivalent produced 2025 2024
kboe kboe
Total produced (working interest) (S)((i)) 15,675 14,909
(i) Production 1,161 kboe associated with Seligi 1a gas (2024: 724 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 2025 2024
$/Boe $/Boe
Production costs (Q/S) 22.0 20.6
Tariff and transportation expenses (R/S) 4.4 4.7
Total unit opex ((Q + R)/S) 26.4 25.3
Realised (gain)/loss on derivative contracts (P/S) (1.3) 0.3
Total unit opex including hedging ((P + Q+ R)/S) 25.1 25.6
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