Results for the year ended 31 December 2025

About this update from Enquest Plc

[{"type":"text","content":"\n \n EnQuest PLC, 25 March 2026 \n Results for the year ended 31 December 2025 and 2026 outlook \n Unless otherwise stated, all figures are in US Dollars. \n Comparative figures for the Income Statement relate to the year ended 31 December 2024 and the Balance Sheet as at 31 December 2024. \n Alternative performance measures are reconciled within the 'Glossary - Non-GAAP measures' at the end of the Financial Statements. \n   \n EnQuest Chief Executive, Amjad Bseisu, said: \n \"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. \n 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. \n 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. \n 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. \n 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. \n \"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.\" \n 2025 performance \n § EnQuest operates 97% of its asset portfolio, and in 2025, the Group delivered another year of top quartile performance. \n § 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. \n § Reported production for the year, which includes Vietnam volumes from 9 July, was 42,945 Boepd (2024: 40,736 Boepd). \n § 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. \n § Investment in fast payback projects grew and diversified production, whilst lowering unit costs and reducing emissions. \n § 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%. \n § 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. \n § 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. \n § 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. \n § New country entries enhance diversified growth across South East Asia, targeting c.35 Kboed in net production in the region by 2030. \n § 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). \n § 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. \n Financial highlights \n § 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. \n § With the RBL fully undrawn at year end, cash and available facilities totalled $678.6 million (31 December 2024: $474.5 million). \n § 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. \n § 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. \n § Net $238.9 million gain on settlement of the Magnus contingent consideration simplifies EnQuest's balance sheet. \n § 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. \n § 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. \n § The Group declared its maiden dividend of c.$15 million, which was paid in June 2025. \n 2026 outlook \n § EnQuest is focused on delivering continued operational excellence and value-accretive transactions in the UK and in South East Asia. \n § Credit-enhancing settlement of the Magnus contingent consideration, completed in February for $60.0 million. \n § 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. \n § A six-well Magnus infill drilling programme and production-enhancing well interventions are due to commence in Q2 2026. \n § Net Group production is expected to average between 41,000 and 45,000 Boepd. \n § 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. \n § 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. \n § Operating expenditure expected to total c.$450 million; capital investment expected to total c.$160 million; Decommissioning expenditure expected to total c.$60 million. \n § 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. \n § The Group is pleased to propose a 2025 final dividend of 0.8 pence per share, equivalent to c.$20 million, payable in June 2026 following shareholder approval at the Group's Annual General Meeting. \n   \n Production and financial information \n \n \n \n \n Macro conditions \n \n \n 2025 \n \n \n 2024 \n \n \n   \n \n \n Change \n   \n \n \n \n \n Brent oil price 4 ($/bbl) \n \n \n 68.2 \n \n \n 80.5 \n \n \n \n \n \n -15.3% \n \n \n \n \n Natural gas price 5 (GBp/Therm) \n \n \n 88.3 \n \n \n 83.6 \n \n \n \n \n \n +5.6% \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n Alternative performance measures ('APMs') \n \n \n 2025 \n \n \n 2024 \n \n \n   \n \n \n Change \n \n \n \n \n Production (Boepd) \n \n \n 42,945 \n \n \n 40,736 \n \n \n \n \n \n 5.4% \n \n \n \n \n Realised oil price ($/bbl) 1,2 \n \n \n 68.8 \n \n \n 80.2 \n \n \n \n \n \n -14.2% \n \n \n \n \n Average unit operating costs ($/Boe) 2 \n \n \n 25.1 \n \n \n 25.6 \n \n \n \n \n \n -2.0% \n \n \n \n \n Adjusted EBITDA ($m) 2 \n \n \n 503.8 \n \n \n 673.9 \n \n \n \n \n \n -25.2% \n \n \n \n \n Cash expenditures ($m) \n \n \n 236.0 \n \n \n 313.4 \n \n \n \n \n \n -24.7% \n \n \n \n \n Capital 2 \n \n \n 179.2 \n \n \n 252.9 \n \n \n \n \n \n -29.1% \n \n \n \n \n Decommissioning \n \n \n 56.8 \n \n \n 60.5 \n \n \n \n \n \n -6.1% \n \n \n \n \n Adjusted free cash flow ($m) 2 \n \n \n 8.7 \n \n \n 53.2 \n \n \n \n \n \n -83.6% \n \n \n \n \n \n \n \n   \n \n \n   \n \n \n \n \n \n \n \n \n \n \n \n \n \n End 2025 \n \n \n End 2024 \n \n \n \n \n \n \n \n \n \n \n EnQuest net (debt)/cash ($m) 2 \n \n \n (433.9) \n \n \n (385.8) \n \n \n \n \n \n 12.5% \n \n \n \n \n   \n \n \n   \n \n \n   \n \n \n \n \n \n   \n \n \n \n \n Statutory measures \n \n \n 2025 \n \n \n 2024 \n \n \n \n \n \n Change \n % \n \n \n \n \n Reported revenue and other operating income ($m) 3 \n \n \n 1,118.3 \n \n \n 1,180.7 \n \n \n \n \n \n -5.3% \n \n \n \n \n Cost of sales ($m) \n \n \n (837.5) \n \n \n (787.4) \n \n \n \n \n \n 6.4% \n \n \n \n \n Reported gross profit ($m) \n \n \n 280.8 \n \n \n 393.3 \n \n \n \n \n \n -28.6% \n \n \n \n \n Reported profit/(loss) after tax ($m) \n \n \n 1.6 \n \n \n 93.8 \n \n \n \n \n \n -98.3% \n \n \n \n \n Reported basic earnings/(loss) per share (cents) \n \n \n 0.1 \n \n \n 5.0 \n \n \n \n \n \n -82.0% \n \n \n \n \n Net cash flow from operating activities ($m) \n \n \n 362.7 \n \n \n 507.6 \n \n \n \n \n \n -28.5% \n \n \n \n \n Net increase/(decrease) in cash and cash equivalents ($m) \n \n \n (24.5) \n \n \n (27.7) \n \n \n \n \n \n 11.6% \n \n \n \n \n   \n Notes: \n 1 Including realised gains of $8.7 million (2024: realised losses of $12.9 million) associated with EnQuest's oil price hedges \n 2 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP Measures' starting on page 61. \n 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 \n 4 Source is Reuters Factset \n 5 Source is ICIS Heren NBP day-ahead \n - Ends - \n   \n For further information, please contact: \n   \n \n \n \n \n EnQuest PLC \n \n \n Tel: +44 (0)20 7925 4900 \n \n \n \n \n Amjad Bseisu (Chief Executive) \n \n \n   \n \n \n \n \n Jonathan Copus (Chief Financial Officer) \n \n \n   \n \n \n \n \n Craig Baxter (Head of Investor Relations and Corporate Affairs) \n \n \n   \n \n \n \n \n   \n \n \n   \n \n \n \n \n Teneo \n \n \n Tel: +44 (0)20 7353 4200 \n \n \n \n \n Martin Robinson \n Harry Cameron \n \n \n   \n \n \n \n \n                 \n Presentation to Analysts and Investors A presentation to analysts and investors will be held at 10:30 today - London time, via Investor Meet Company. \n The presentation is open to all existing and potential shareholders. Questions can be submitted pre-event via your Investor Meet Company dashboard, or at any time during the live presentation. \n Investors can sign up to Investor Meet Company for free and add to meet ENQUEST PLC  via: \n https://www.investormeetcompany.com/enquest-plc/register-investor \n Investors who already follow ENQUEST PLC  on the Investor Meet Company platform will automatically be invited. \n Notes to editors \n This announcement has been determined to contain inside information. The person responsible for the release of this announcement is Kate Christ, Company Secretary. \n ENQUEST \n 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. \n EnQuest PLC trades on the London Stock Exchange. \n Please visit our website www.enquest.com for more information on our global operations. \n   \n 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. \n   \n \n \n   \n Chief Executive's report \n A year defined by operational excellence, enhanced foundations and strategic clarity \n 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. \n We are building on strong foundations. In 2025, our operational and financial performance was robust, and we simplified and enhanced our balance sheet. \n At a time when the UK fiscal regime remains challenging, we also took decisive steps to accelerate our diversification into high-growth Asian markets. \n 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. \n 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. \n Delivering safe, reliable performance across our portfolio \n 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. \n § 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%. \n § 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. \n § Settlement of the Magnus contingent consideration mechanism significantly enhances our balance sheet and demonstrates our long-term commitment to this core asset. \n § 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. \n § 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%. \n § 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. \n § 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. \n § 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. \n 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. \n 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. \n Strategic progress: diversifying the portfolio and expanding our footprint \n We also made significant strides in broadening our geographic and commodity exposure. \n 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. \n 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. \n 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. \n Financial discipline enabling shareholder returns and future growth \n 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. \n 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. \n 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. \n 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. \n 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. \n 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. \n 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. \n Navigating a shifting geopolitical landscape \n 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. \n 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. \n 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. \n 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. \n 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. \n 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. \n Building a lower-carbon future while maintaining safe operations \n 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. \n 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%. \n 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. \n 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. \n 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. \n 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. \n Looking ahead: a transformational year for EnQuest \n 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. \n 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. \n 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. \n 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. \n Closing remarks \n 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. \n 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. \n   \n Operational review \n 2025 saw the Group deliver 89% production efficiency across its operated portfolio. \n EnQuest continues to demonstrate its differentiated operating capability, founded on deep expertise in late-life asset management and complemented by sector-leading decommissioning performance. \n 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. \n 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. \n 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. \n 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. \n 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. \n Operational excellence \n 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. \n Excluding the impact of a third-party infrastructure outage, which saw Magnus production shut-in for five weeks, Group production efficiency was 92%. \n 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%. \n Further, the NSTA UKCS production efficiency for floating hubs is 67%. At 95% production efficiency, EnQuest's Kraken FPSO beats that by 28%. \n This exemplary uptime performance extends to the Group's South East Asia business, with 93% uptime at PM8/Seligi and 100% uptime in Vietnam. \n   \n UK Upstream \n 2025 UK operations performance summary \n 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. \n Kraken \n 2025 performance summary \n 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). \n 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. \n 2026 outlook \n 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. \n 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. \n 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. \n Magnus \n 2025 performance summary \n 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. \n 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%. \n 2026 outlook \n 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. \n 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. \n 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. \n 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. \n Greater Kittiwake Area \n 2025 performance summary \n 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. \n 2026 outlook \n 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. \n Non-operated North Sea assets \n 2025 performance summary \n 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. \n 2026 outlook \n At Golden Eagle, a 41-day shutdown is planned during the third quarter. \n At Alba, the most significant activity centres on decommissioning, with the cessation of asset production planned during the summer. \n South East Asia \n PM8/Seligi, Malaysia \n 2025 performance summary \n 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. \n 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. \n 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. \n 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. \n 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. \n 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. \n 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. \n 2026 outlook \n 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. \n 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. \n 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. \n 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. \n Block 12W, Vietnam \n 2025 performance summary \n 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. \n 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. \n 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. \n 2026 outlook \n 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. \n 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. \n Decommissioning \n Performance summary \n 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. \n 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. \n Well decommissioning \n 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. \n 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. \n 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. \n Preparation for removal \n 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. \n 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. \n 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. \n 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. \n 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. \n Asset removals \n 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. \n 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. \n The Heather jacket is scheduled for removal in 2027, which aligns with previously agreed contractual execution windows. \n Midstream \n Safe, stable operations \n 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. \n Decarbonisation \n 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. \n 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. \n 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. \n 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. \n 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. \n People and community \n EnQuest continues to build its community investment on Shetland with contributions to local charities and sports groups, and through its workforce development programmes. \n 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. \n 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. \n 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. \n This year, students are engaged in disciplines as wide-ranging as English language and linguistics, energy transitions and sustainability, mathematics and structural engineering. \n 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. \n Veri Energy \n 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. \n Veri Energy is fuelling the UK's energy transition \n 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. \n Electrification/Onshore wind \n 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. \n E-fuels \n 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 CO 2 . \n 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. \n 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. \n Additional workstreams commencing in 2026 will explore replication of the e-methanol facility and future expansion into downstream e ‑ SAF production. \n 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. \n Carbon capture and storage ('CCS') \n Veri Energy continues to develop a flexible, merchant-market carbon storage solution that can transport and permanently store up to 10mtpa of CO 2 from isolated emitters in the UK and Europe. CO 2 captured by emitters will be transported via ship to SVT from where it will be transported via repurposed pipeline infrastructure, for permanent geological storage in depleted oil and gas reservoirs. \n 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. \n 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 CO 2 emitters to permanently sequester carbon beginning in the early 2030s. \n   \n Financial review \n Introduction \n 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. \n 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. \n 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. \n 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. \n 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). \n 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). \n Income statement \n Revenue \n 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%). \n 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). \n 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. \n 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. \n 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). \n Note: For the reconciliation of realised oil prices see 'Glossary - Non-GAAP measures' starting on page 61 \n Cost of sales \n 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). \n 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. \n 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). \n \n \n \n \n \n \n \n 2025 \n $ million \n \n \n 2024 \n $ million \n \n \n \n \n Production costs \n \n \n 344.5 \n \n \n 307.6 \n \n \n \n \n Tariff and transportation expenses \n \n \n 69.2 \n \n \n 70.5 \n \n \n \n \n Realised (gain)/loss on derivatives related to operating costs \n \n \n (19.7) \n \n \n 4.7 \n \n \n \n \n Operating costs 1 \n \n \n 394.0 \n \n \n 382.8 \n \n \n \n \n Charge/(credit) relating to the Group's lifting position and hydrocarbon inventory \n \n \n 17.4 \n \n \n 2.2 \n \n \n \n \n Other cost of operations \n \n \n 179.6 \n \n \n 135.0 \n \n \n \n \n Depletion of oil and gas assets \n \n \n 267.3 \n \n \n 263.3 \n \n \n \n \n Other cost of sales \n \n \n (20.8) \n \n \n 4.1 \n \n \n \n \n Cost of sales \n \n \n 837.5 \n \n \n 787.4 \n \n \n \n \n Unit operating cost 2 \n \n \n $/Boe \n \n \n $/Boe \n \n \n \n \n - Production costs \n \n \n 22.0 \n \n \n 20.6 \n \n \n \n \n - Tariff and transportation expenses \n \n \n 4.4 \n \n \n 4.7 \n \n \n \n \n Average unit operating cost (excluding gain/loss on derivatives) \n \n \n 26.4 \n \n \n 25.3 \n \n \n \n \n Average unit operating cost (including gain/loss on derivatives) \n \n \n 25.1 \n \n \n 25.6 \n \n \n \n \n   \n Notes: \n 1      See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 61 \n 2      Calculated using production on a working interest basis including Seligi Associated Gas (1a) \n   \n 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). \n Impairment \n 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. \n Other income and expenses \n 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. \n Other expenses include costs associated with Veri Energy, which totalled $3.6 million in the year (2024: $1.7 million). \n Adjusted EBITDA \n 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). \n EnQuest's net debt to last 12-month adjusted EBITDA ratio at 31 December 2025 equalled 0.9x (31 December 2024: 0.6x). \n \n \n \n \n Adjusted EBITDA \n \n \n 2025 \n $ million \n \n \n 2024 \n  $ million \n \n \n \n \n \n \n \n Profit/(loss) from operations before tax and finance income/(costs) \n \n \n 648.8 \n \n \n 311.5 \n \n \n \n \n \n \n \n Net unrealised commodity, foreign exchange and UKA hedge (gain)/loss \n \n \n (77.5) \n \n \n (0.3) \n \n \n \n \n \n \n \n Depletion and depreciation \n \n \n 272.4 \n \n \n 269.3 \n \n \n \n \n \n \n \n Impairment (reversal)/charge \n \n \n (5.8) \n \n \n 71.4 \n \n \n \n \n \n \n \n Change in fair value of contingent consideration \n \n \n (387.1) \n \n \n 15.9 \n \n \n \n \n \n \n \n Net other expenses \n \n \n 21.9 \n \n \n 21.6 \n \n \n \n \n \n \n \n Change in well inventories \n \n \n 2.8 \n \n \n (5.5) \n \n \n \n \n \n \n \n Net foreign exchange revaluation loss/(gain) \n \n \n 28.3 \n \n \n (10.0) \n \n \n \n \n \n \n \n Adjusted EBITDA 1 \n \n \n 503.8 \n \n \n 673.9 \n \n \n \n \n \n \n \n   \n Note: \n 1      See reconciliation of Adjusted EBITDA within the 'Glossary - Non-GAAP measures' starting on page 61 \n Finance costs \n EnQuest's overall net finance costs increased by 7%, to $155.4 million (2024: $144.9 million). \n 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). \n Finance income decreased to $9.2 million reflecting lower interest receivable from bank balances (2024: $14.5 million). \n Profit/loss before tax \n Reflecting the movements above, the Group's profit before tax was $493.4 million (2024: profit of $166.6 million). \n Taxation \n 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. \n 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. \n 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. \n 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. \n 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. \n 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. \n Profit/loss for the period \n 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. \n Earnings per share \n 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). \n Cash flow, EnQuest net debt and liquidity \n 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. \n 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). \n Cash outflow on capital expenditure is set out in the table below: \n \n \n \n \n Capital expenditure \n \n \n 2025 \n $ million \n \n \n 2024 \n $ million \n \n \n \n \n North Sea \n \n \n 128.0 \n \n \n 230.4 \n \n \n \n \n Malaysia and Vietnam \n \n \n 48.5 \n \n \n 19.0 \n \n \n \n \n Exploration and evaluation \n \n \n 2.7 \n \n \n 3.5 \n \n \n \n \n \n \n \n 179.2 \n \n \n 252.9 \n \n \n \n \n   \n 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). \n 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). \n The movement in EnQuest net debt was as follows: \n \n \n \n \n \n \n \n $ million \n \n \n \n \n EnQuest net debt 1 January 2025 \n \n \n (385.8) \n \n \n \n \n Net cash flows from operating activities \n \n \n 362.7 \n \n \n \n \n Cash capital expenditure \n \n \n (179.2) \n \n \n \n \n Net interest and finance costs paid \n \n \n (91.7) \n \n \n \n \n Finance lease payments \n \n \n (83.1) \n \n \n \n \n Dividend paid \n \n \n (15.3) \n \n \n \n \n Vietnam asset acquisition \n \n \n (20.3) \n \n \n \n \n RBL re-financing fees \n \n \n (17.8) \n \n \n \n \n Other movements, primarily net foreign exchange on cash and debt \n \n \n (3.4) \n \n \n \n \n EnQuest net debt 31 December 2025 1 \n \n \n (433.9) \n \n \n \n \n   \n Note: \n 1      See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 61 \n \n \n \n \n EnQuest net debt \n \n \n 31 December \n  2025 \n $ million \n \n \n 31 December 2024 \n $ million \n \n \n \n \n Bonds \n \n \n 644.4 \n \n \n 632.1 \n \n \n \n \n Senior secured debt facility ('RBL') \n \n \n - \n \n \n - \n \n \n \n \n Vendor loan facility \n \n \n 22.1 \n \n \n - \n \n \n \n \n SVT working capital facility \n \n \n 36.3 \n \n \n 33.9 \n \n \n \n \n Cash and cash equivalents \n \n \n (268.9) \n \n \n (280.2) \n \n \n \n \n EnQuest net debt 1 \n \n \n 433.9 \n \n \n 385.8 \n \n \n \n \n   \n Note: \n 1      See reconciliation of EnQuest net debt within the 'Glossary - Non-GAAP measures' starting on page 61 \n   \n EnQuest continues to monitor the debt capital markets and would look to opportunistically refinance its existing 2027 bond maturities, subject to market conditions. \n Balance sheet \n 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. \n Assets \n 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. \n Liabilities \n 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). \n Financial risk management \n 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. \n Going concern \n During 2025, EnQuest has continued to focus on optimisation of its capital structure and the maximisation of its available transactional capacity. \n 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. \n 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. \n 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. \n 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'): \n § 10.0% discount to Base Case prices, resulting in Downside Case prices of $63.0/bbl for 2026 and 2027; \n § Production risking of 5.0%; and \n § 2.5% increase in operating costs. \n 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\"). \n 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. \n Viability Statement \n 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. \n 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. \n Commodity prices \n 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. \n Access to capital \n Prolonged low oil prices, cost increases and production delays or outages could threaten the Group's liquidity and access to funding. \n 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. \n 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. \n \n \n Oil and gas reserves and resources \n EnQuest asset base as at 31 December 2025 \n \n \n \n \n \n \n \n North Sea \n \n \n South East Asia \n \n \n Total \n \n \n \n \n \n \n \n Oil and NGLs \n MMbbls \n \n \n Gas \n Bcf \n \n \n Total \n MMboe \n \n \n Oil and NGLs \n MMbbls \n \n \n Gas \n Bcf \n \n \n Total \n MMboe \n \n \n Oil and NGLs \n MMbbls \n \n \n Gas \n Bcf \n \n \n Total \n MMboe \n \n \n \n \n 2P reserves \n(working interest) 1,2,3,5,6 \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n 1 January 2025 \n \n \n 123.3 \n \n \n 52.7 \n \n \n 132.3 \n \n \n 20.0 \n \n \n 94.2 \n \n \n 36.3 \n \n \n 143.3 \n \n \n 146.9 \n \n \n 168.6 \n \n \n \n \n Revisions 4 \n \n \n 0.5 \n \n \n 0.3 \n \n \n 0.6 \n \n \n 2.0 \n \n \n 30.7 \n \n \n 7.6 \n \n \n 2.6 \n \n \n 31.0 \n \n \n 8.2 \n \n \n \n \n Production \n \n \n (10.5) \n \n \n (5.2) \n \n \n (11.4) \n \n \n (2.6) \n \n \n (1.7) \n \n \n (2.9) \n \n \n (13.1) \n \n \n (6.9) \n \n \n (14.3) \n \n \n \n \n 31 December 2025 \n \n \n 113.3 \n \n \n 47.8 \n \n \n 121.5 \n \n \n 19.5 \n \n \n 123.2 \n \n \n 41.0 \n \n \n 132.8 \n \n \n 171.0 \n \n \n 162.5 \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n 2C resources \n(working interest) 1,2,7,8 \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n \n 1 January 2025 \n \n \n 305.1 \n \n \n 18.1 \n \n \n 308.2 \n \n \n 17.8 \n \n \n 160.2 \n \n \n 45.4 \n \n \n 322.9 \n \n \n 178.3 \n \n \n 353.6 \n \n \n \n \n Revisions, additions and relinquishments \n \n \n (0.4) \n \n \n 0.0 \n \n \n (0.4) \n \n \n 21.1 \n \n \n 403.7 \n \n \n 98.9 \n \n \n 20.7 \n \n \n 403.7 \n \n \n 98.5 \n \n \n \n \n 31 December 2025 \n \n \n 304.8 \n \n \n 18.1 \n \n \n 307.9 \n \n \n 38.9 \n \n \n 563.9 \n \n \n 144.3 \n \n \n 343.6 \n \n \n 582.0 \n \n \n 452.1 \n \n \n \n \n   \n Notes: \n 1      Reserves and resources are quoted on a working interest basis \n 2      2P reserves and 2C resources have been assessed by the Group's internal reservoir engineers, utilising geological, geophysical, engineering and financial data \n 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 \n 4      Includes newly acquired Block 12W in Vietnam \n 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 \n 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) \n 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 \n 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 \n 9      Rounding may apply \n   \n Risks and uncertainties \n Management of risks and uncertainties \n 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. \n 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. \n 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: \n § 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 \n § 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 \n § 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 \n § The Group sets clear tolerances for all material operational risks to minimise overall operational losses, with zero tolerance for criminal conduct \n 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. \n 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. \n 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. \n 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. \n The risks that are no longer considered principal in nature are: Competition; Portfolio Concentration; International Business; JV Partners; Reputation; and Human Resources. \n 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. \n 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. \n Near-term and emerging risks \n 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. \n Ongoing geopolitical situation \n 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. \n Geographical diversification \n 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. \n Climate change risks \n 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. \n   \n Climate change \n RISK \n 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 Envi...

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