RNS Number : 5284A
EnQuest PLC
24 September 2025
EnQuest PLC
Results for the six months ended 30 June 2025
24 September 2025
Unless otherwise stated, all figures are in US Dollars.
Comparative figures for the Income statement relate to the period ended 30 June 2024 and the Balance sheet as at 31 December 2024. Alternative performance measures are reconciled within the 'Glossary - Non-GAAP measures' at the end of the Financial Statements.
EnQuest Chief Executive, Amjad Bseisu, said:
"Consistent with our top-quartile performance over several years, EnQuest has again delivered exemplary production efficiency - which averaged 89% across the portfolio in the first half of 2025, with production in line with guidance. Production-enhancing scopes of work and major maintenance campaigns were all completed on schedule, and it has been pleasing to see Magnus hitting a five-year production peak in recent months. We continue to demonstrate sector leadership in decommissioning, exemplified by the 15,300-tonne Heather topsides lift in August, which is the heaviest such lift in the North Sea in 2025.
"In South East Asia, EnQuest continues to deliver diversified growth. Building upon the DEWA PSC awards and the expansion of the Seligi gas agreement in late 2024, the Group has since completed the Vietnam acquisition; signed PSC agreements alongside the bp Tangguh partnership in Indonesia; and been awarded a PSC agreement in Brunei Darussalam. EnQuest is well respected in the region and, having been named Malaysia Upstream Operator of the Year for a second successive year, we have a robust platform from which to add further value-adding growth in South East Asia.
"We remain very clear that we are committed to continued investment in our UK business, targeting material, value-enhancing growth. Our near-term pivot to investment outside of the UK underlines, however, how successive UK governments have made the UK North Sea globally uncompetitive through fiscal policy. The UK remains the only country worldwide levying a windfall tax on energy profits, in an environment where even the Office of Budget Responsibility acknowledges that prices are at, or below, historic norms and therefore no windfall exists. Following a well-run consultation on the future of the UK's oil and gas fiscal system, we believe that the UK Government now has a tool with which to revitalise this sector; materially increasing investment and tax revenues to Treasury, improving the UK's energy security in a volatile macro environment, and protecting jobs across the country, which are currently being lost at a rate of 1,000 per month. We implore the government to act now to avoid the accelerated decline of this industry and the resulting death of the UK's energy transition ambitions.
"EnQuest's growth strategy remains robust, with a focus on delivering a transformative UK acquisition; utilising our differentiated operating capability and significant tax asset to deliver material incremental value. The progress made over the past eight years to strengthen our balance sheet provides us with strategic choices and, following the payment of the Group's maiden dividend, we will continue to make disciplined, value-adding strategic decisions for the benefit of our shareholders."
H1 2025 performance
· Net production averaged 43,392 Boepd, including proforma 1H production from Vietnam. Excluding Vietnam, Group production was 38,257 Boepd (2024: 42,771 Boepd); strong uptime across the portfolio and a successful Magnus infill drilling campaign being offset by a third-party infrastructure outage that shut Magnus in for almost five weeks.
· This outage lowered Group H1 production by c.3,500 barrels per day, equivalent to the deferral of one cargo sale out of the period. Strong underlying asset performance, optimised production at Magnus and confidence in the second half outlook mean that full year production guidance remains unchanged at 40 to 45 Kboed.
· Revenue and other operating income fell c.6% (2025: $549.1 million, 2024: $586.0 million); cost of sales rose c.10%; and the Group reported a pre-tax profit of $65.6 million (2024: $111.3 million).
· A 14% fall in Brent was largely offset by the Group's active portfolio of hedging and a 37% rise in gas prices. Underlying operating costs were held flat, despite an 11% weakening in USD.
· A $123.9 million non-cash adjustment (due to the two-year extension of the EPL 'windfall tax') distorts the H1 tax charge. Adjusting for this and other exceptional items, EnQuest reported a net loss of $43.1 million (2024: adjusted net profit $84.2 million); which, inclusive of these items, rises to a statutory net loss of $173.5 million (2024: statutory net profit $30.3 million).
· Free cash flow totalled $32.7 million (2024: $55.5 million) and after payment of a $15 million dividend, Net Debt at 30 June totalled $376.6 million (end 2024: $385.8 million). Cash and undrawn facilities rose to $577.8 million (end 2024: $474.5 million).
· Post the balance sheet date, in July, EnQuest paid $104.1 million in relation to the UK Energy Profits Levy, as well as a $22.2 million completion payment associated with the acquisition of Block 12W in Vietnam.
· EnQuest remains fully focused on delivering its base operations and securing transformational transactional growth within its North Sea business, enhanced by the Group's advantaged UK tax position.
South East Asia - Delivering diversified growth
· EnQuest completed the Vietnam acquisition in early July. The assets are performing strongly (H1 net production of 5.1kboe/d, slightly above guidance and including the planned June shutdown). The Group has identified a range of upside opportunities.
· Following award of an extension to the Seligi 1b gas agreement in Q4-24, EnQuest has utilised its operational expertise to accelerate first gas to Q1 2026 (from Q3 2026). The Group also continues to progress DEWA (Sarawak, Malaysia PSC awarded Q4 2024) and has recently announced new country entries, via PSC awards, in Indonesia and Brunei Darussalam.
· These exciting portfolio additions provide a pathway for EnQuest to grow its South East Asian production from 8,149 Boepd in 2024 to 15,000 Boepd during 2026, and to more than 35,000 Boepd by the end of the decade. With a strong reputation in the region for delivery and operational excellence, EnQuest considers this to be the start of its South East Asian growth journey.
2025 guidance and outlook
EnQuest remains on track to deliver net production within the guidance range of 40,000 to 45,000 Boepd communicated at the start of the year (inclusive of Vietnam, with full year pro forma production of c.5 Kboed). During the unscheduled Magnus production shut-in, EnQuest proactively accelerated maintenance work, and the next planned maintenance shutdown at the field will be in 2026.
Full year expectations for each of operating, cash capital and abandonment expenditures remain unchanged from the Group's original guidance at c. $450 million, $190 million and $60 million, respectively, all on a full year pro forma basis, including Vietnam.
In the period to 30 June 2025, EnQuest benefited from its steps in H2 2024 to reposition and expand its programme of hedging. For the period September to December 2025, the Group has c.1.6 MMbbls of production hedged, using swaps at an average price of $71/bbl. For 2026, EnQuest has a further c.4.2 MMbbls of production hedged, utilising swaps at an average price of $69/bbl, with an additional 0.1 MMbbls hedged using collars with a floor price of $53/bbl and ceiling price of $81/bbl.
EnQuest's business development team remains very active in both the UK North Sea and South East Asia, as the Group pursues transformative growth.
Production and financial information
Alternative performance measures ('APMs')
For the period to 30 June 2025
For the period to 30 June 2024
Change %
Production (Boepd)1
38,257
42,771
(10.6)
Realised oil price ($/bbl)2,3
71.0
83.4
(14.9)
Operating costs ($m)3
182.8
183.0
(0.1)
Average unit operating costs ($/Boe)3
27.8
22.8
21.9
Adjusted (loss)/profit attributable to shareholders
(43.1)
84.2
-
Adjusted EBITDA ($m)3
234.6
367.5
(36.2)
Cash expenditures ($m)
114.6
126.5
(9.4)
Capital
83.2
95.0
(12.4)
Abandonment
31.4
31.5
(0.3)
Adjusted free cash flow ($m)3
32.7
55.5
(41.0)
30 June 2025
31 December 2024
EnQuest net debt ($m)3
(376.6)
(385.8)
(2.4)
Statutory IFRS measures
For the period to 30 June 2025
For the period to 30 June 2024
Change %
Reported revenue and other operating income ($m)4
549.1
586.0
(6.3)
Cost of sales ($m)
388.9
352.3
10.4
Reported gross profit ($m)
160.2
233.7
(31.5)
Reported (loss)/profit after tax ($m)
(173.5)
30.3
-
Reported basic (loss)/earnings per share (cents)
(9.3)
1.6
-
Cash generated from operations ($m)
215.2
368.9
(41.7)
Net increase/(decrease) in cash and cash equivalents ($m)5
34.8
27.0
28.9
Notes:
1 Production figure for the first half of 2025 includes 2,748 Boepd associated with Seligi gas (2024: 1,614 Boepd)
2 Including realised gains of $1.0 million (2024: realised losses of $10.7 million) associated with EnQuest's oil price hedges
3 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 31. Note, EnQuest defines net debt as excluding finance lease liabilities
4 Including net realised and unrealised gains of $34.2 million (2024: net realised and unrealised losses of $12.6 million) associated with EnQuest's oil price hedges
5 Excludes foreign exchange impact of $15.6 million (2024: $(3.3) million)
- Ends -
For further information, please contact:
EnQuest PLC
Tel: +44 (0)20 7925 4900
Amjad Bseisu (Chief Executive Officer)
Jonathan Copus (Chief Financial Officer)
Craig Baxter (Head of Investor Relations and Corporate Affairs)
Teneo
Tel: +44 (0)207353 4200
Martin Robinson
Harry Cameron
Presentation to Analysts and Investors
A presentation to analysts and investors will be held at 10.30 today - London time. The presentation will be accessible via a webcast by clicking here.
EnQuest's investor relations team will be hosting a presentation via Investor Meet Company, primarily focused on the Company's retail investors on 14 October at 14:00 - London time.
The presentation is open to all existing and potential shareholders. Questions can be submitted pre-event via your Investor Meet Company dashboard up until 9am the day before the meeting or at any time during the live presentation.
Investors can sign up to Investor Meet Company for free and add the Company to meet ENQUEST PLC via:
https://www.investormeetcompany.com/enquest-plc/register-investor
Investors who already follow ENQUEST PLC on the Investor Meet Company platform will automatically be invited.
Notes to editors
This announcement has been determined to contain inside information. The person responsible for the release of this announcement is Kate Christ, Company Secretary.
ENQUEST
EnQuest is providing creative solutions through the energy transition. As an independent energy company with operations in the UK North Sea and across South East Asia, the Group's strategic vision is to be the partner of choice for the responsible management of existing energy assets, applying its core capabilities to create value through the transition.
EnQuest PLC trades on the London Stock Exchange.
Please visit our website www.enquest.com for more information on our global operations.
Forward-looking statements: This announcement may contain certain forward-looking statements with respect to EnQuest's expectations and plans, strategy, management's objectives, future performance, production, reserves, costs, revenues and other trend information. These statements and forecasts involve risk and uncertainty because they relate to events and depend upon circumstances that may occur in the future. There are a number of factors which could cause actual results or developments to differ materially from those expressed or implied by these forward-looking statements and forecasts. The statements have been made with reference to forecast price changes, economic conditions and the current regulatory environment. Nothing in this announcement should be construed as a profit forecast. Past share performance cannot be relied upon as a guide to future performance.
Operating Review
Upstream operations
Group performance summary
Net production averaged 43,392 Boepd, including 1H pro forma production from Vietnam. Excluding Vietnam, production of 38,257 Boepd (2024: 42,771 Boepd) reflected strong production efficiency across the portfolio, partially offsetting natural field declines and an unplanned five-week outage at Magnus, due to a third-party pipeline outage. Without this unplanned third-party outage, production for the first half of 2025 would have been c.41.8 Kboed (excluding Vietnam).
Given continued challenges presented by the UK fiscal system, the Group continues to evaluate its programme of capital investment to ensure the protection and enhancement of value for investors, by focusing on low-cost, fast-payback activities that enhance production.
UK operations
Magnus
In the first half of 2025 the Magnus field was shut in for five weeks due to an unplanned outage of the third-party operated Ninian Central Pipeline. This outage had the effect of reducing EnQuest production by c.3.5 Kboed for the period.
Average production at Magnus for the first six months of 2025 was 12,989 Boepd, 14% lower than the first half of 2024 (15,163 Boepd). Production efficiency for the first half of the year was 73% (2024: 86%). Excluding the impact of the third-party infrastructure outage, Magnus production efficiency for the period to 31 August 2025 was 95%.
Following the reinstatement of Magnus production in May, asset production has benefitted from the successful two-well infill drilling programme, with both wells producing above mid-case expectations, well interventions and well optimisation work undertaken during the outage. Reflecting these activities, in the period June to August 2025 EnQuest has delivered the best three-monthly oil production rate at Magnus since early 2020, peaking at 18,882 barrels of oil per day in mid-July. In addition, the utilisation of a fifth water injector has provided a 20% uplift in Magnus water injection capacity, with field average water cut reduced back to 2017 pre-acquisition levels of 85%. The asset will now take a short break from drilling activity, with production to be optimised through maximising water injection and sweep efficiencies. The Group expects to return to drilling at Magnus in 2026 with a six-well infill drilling programme.
Having proactively completed key maintenance scopes during the production shut-in, the seven-day maintenance shutdown originally planned for the second half of the year is no longer required. Accordingly, the next planned shutdown at Magnus will be in 2026.
Kraken
Average net production of 11,481 Boepd (2024: 13,637 Boepd) in the first half of 2025 was driven by 96% production uptime and 94% water injection efficiency. This continued exemplary performance represents a standard of operation that is c.25% better than the UK North Sea benchmark for floating hubs.
The EnQuest team is focused on enhancing the next phase of Kraken operations; maintaining best-in-class FPSO production efficiency through targeted investment in maintenance and accessing the remaining 2P/2C reserves through future infill drilling. Work is also ongoing to mature the Enhanced Oil Recovery ('EOR') project, which represents a material upside to Kraken's value.
The Group is also advancing the Bressay gas import project as a subsea tie-back to Kraken. By displacing the majority of the diesel currently used to power Kraken operations, this project is designed to drive both a material reduction in FPSO emissions and operating costs. The asset team is also in the early stages of assessing a flare gas recovery solution for Kraken, which has the potential to provide another source of gas for powering FPSO operations. Together, these gas projects are well positioned to drive a step-change reduction in Kraken's carbon footprint and operating cost base.
Other Upstream assets
Production at the Greater Kittiwake Area ('GKA') for the first six months of 2025 averaged 2,001 Boepd (2024: 2,637 Boepd). This was driven by natural field decline, partially offset by strong uptime of 83% (2024: 89%). The planned annual maintenance shutdown at GKA was delivered in August, on schedule, and with all scopes completed.
Average net production at Golden Eagle was 2,986 Boepd (2024: 3,614 Boepd) in the first half of the year, with asset production efficiency of 97% (2024: 94%).
South East Asia operations
PM8/Seligi - Malaysia
For the first six months of 2025, average production in Malaysia was 8,427 Boepd (2024: 7,720), driven by 93% production efficiency, incremental gains from the idle well restoration ('IWR') programme, and strong base well performance.
The Group has completed all four wells in the 2025 infill drilling programme, with production rates in line with expectations. In addition, five wells have been returned to production via IWR, with a further well reinstated through a workover scope, adding more than 2 Kboed of incremental production at PM8/Seligi.
The 2025 shutdown was completed ahead of schedule in early July, with all scopes completed.
Seligi gas, which is produced and handled by EnQuest in exchange for a gas handling and delivery fee, represented 2,748 Boepd of year-to-date production (H1 2024: 1,614 Boepd). The Seligi gas agreement has now been expanded to develop and commercialise the non-associated gas volumes in the field on an accelerated basis, increasing EnQuest's net production capability by c.6 Kboed to meet expected demand in Peninsular Malaysia from early-2026.
EnQuest was again awarded two major accolades at the PETRONAS Emerald Awards. This is the second successive year that EnQuest has been named Operator of the Year, the first time in the history of the awards that this accolade has been retained. This award reaffirms EnQuest's reputation as a top-quartile operator in the region, a point which the Group has successfully leveraged into regional growth.
Block 12W - Vietnam
On 9 July, EnQuest completed the acquisition of Harbour Energy's Vietnam business, anchored by operatorship of a 53.125% equity interest in the Chim Sáo and Dua production fields ('Block 12W'). The headline value of the transaction was $85.1 million and, net of interim period cash flows (generated since the effective date of 1 January 2024), the aggregate consideration paid by EnQuest was circa $25.7 million.
Block 12W operations in the first half of the year have been strong, with a planned annual maintenance shutdown completed on time and within budget during June. The successful execution of three of six scheduled well intervention scopes has added c.1,200 boepd of gross production. Underpinned by production efficiency of 87.4%, net asset production in the first half of 2025 totalled 5.1 Kboed, which was slightly higher than pre-completion guidance, with the potential for natural field declines to be offset by further in-year upside relating to well intervention activity and performance and the positive impact of a production-enhancing chemical soaking process undertaken during the shutdown.
As at 1 January 2025, net 2P reserves and 2C resources across the fields totalled 7.5 million boe and 4.9 million boe, respectively. EnQuest is now assessing additional Block 12W prospectivity and has begun work to deploy its proven late-life and FPSO asset management expertise to maximise value and translate discovered resources into reserves at the fields (which are spread across three gas discoveries and several additional targets), with a view to extending the PSC beyond its current end date of November 2030.
DEWA Project - Malaysia
With EnQuest as operator (at a working interest of 42%), petrophysical, geophysical, and resource assessment work on the DEWA PSC cluster has been completed, with dynamic modelling now in place for the six highest-priority fields. Initial development concept planning has identified options for produced gas to be transported to the MLNG plant in Bintulu, with technical and economic viability screening ongoing. The target is to have a draft field development and abandonment plan ('FDAP') in place by the end of 2025, in order to commence commercial negotiations.
The anticipated first gas date, subject to Final Investment Decision ('FID'), is by the end of 2028, with the initial development phase delivering c.7 Kboed of gas production and c.24 MMboe of additional reserves. Other fields within the PSC area are also being evaluated for future phased development.
Block C - Brunei
Following the Block C PSC award in July 2025, with EnQuest as operator on a 100% working interest basis, work is ongoing to form a 50:50 Joint Venture Company between the Government of Brunei and EnQuest. In the meantime, work has commenced to finalise the resources and evaluate gas development concepts for delivery to the BLNG plant in Lumut, Brunei. With the potential for first gas from Block C during 2029, EnQuest anticipates that this development could deliver c.12 Kboed net production and add c.55 MMboe of additional reserves from the initial fields developed, based on a 50% net share. The Group will also assess additional fields in the block concurrently, in order to evaluate future development plans.
Gaea & Gaea II PSCs - Indonesia
Having been confirmed as the successful bidders in April 2025, EnQuest and its joint venture partners completed the signing of the Gaea and Gaea II PSCs on 1 August 2025. EnQuest has a 40% participating interest in the blocks and is the PSC operator, alongside its partners, the Tangguh Joint Venture (with 40% participating interest, comprising BP Exploration Indonesia Limited, MI Berau B.V. (an INPEX and Mitsubishi joint venture company), CNOOC Southeast Asia Limited, ENEOS Xplora Inc., Indonesia Natural Gas Resources Muturi, Inc. (an LNG Japan Corporation), and KG Wiriagar Petroleum Ltd (a Mitsui & Co., Ltd)), and PT Agra Energi Indonesia (20% participating interest).
The resource potential of Gaea and Gaea II is estimated to be in excess of 100 Tscf by the Indonesian Ministry of Energy and Mineral Resources, with the blocks located in proximity to the bp-operated Tangguh LNG facility. At this stage, the focus of the JV is on maturing targets for further geological and geophysical study, seismic reprocessing and future 2D seismic acquisition across both blocks, with the potential for high-impact exploration targeting large potential gas volumes in a frontier region.
Decommissioning
2025 has seen EnQuest continue to demonstrate its leadership in decommissioning, delivering top-quartile well plug and abandonment ('P&A') and completing key project milestones at Heather and Thistle. Having completed the P&A of the final seven Heather wells during 1H 2025, EnQuest has executed the P&A of 81 North Sea wells since 2022 (39 at Heather and 42 at Thistle).
This work is being executed at sector-leading cost by EnQuest's dedicated in-house team, with an average EnQuest well P&A scope completed 25% faster than the North Sea Transition Authority benchmark.
The final disembarkation of the Heather platform was completed in mid-April. After 47 years of North Sea operations, the removal of the Heather Alpha topsides was safely completed on 11 August. The Allseas Pioneering Spirit heavy lift vessel removed the 15,300 tonne topsides in what is the largest single lift planned in the North Sea this year. This lift marked the culmination of significant planning, engineering, and offshore preparation work undertaken by EnQuest's in-house decommissioning team, working alongside Allseas and other specialist contractors.
Demonstrating the Group's commitment to safe, responsible operations, the Heather topsides were transferred by barge to Frederikshavn in Denmark, where the structure is in the process of being dismantled. It is expected that more than 95% of the structure will be recycled and repurposed, ensuring maximum material recovery and minimising the carbon footprint of the project.
At Thistle, the team is on track to complete disembarkation in the first quarter of 2026, following the P&A of 41 wells in total. Preparatory works have commenced in support of the platform's removal.
In August, EnQuest signed a multi-year contract with Well-Safe, which secures the Well-Safe Defender rig for a minimum of 230 days across 2026 and 2027. The contract also includes options for EnQuest to add further activities between 2028 and 2034, creating the potential for a strategic partnership that would secure vital supply chain resources in the North Sea well into the next decade. This rig will initially be utilised to complete the proactive P&A of Magnus subsea wells, commencing in 2026. The EnQuest team continues to work on the basis that subsea decommissioning activities can be optimised by utilising a portfolio approach across the fields, with the scheduling of activity primarily driven by well integrity.
In Malaysia, the EnQuest decommissioning team was recognised with an award for Abandonment Excellence at the PETRONAS Emerald Award, following the successful execution of a six-well P&A campaign during 2024. In 2025, EnQuest plans to complete 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.
Midstream
EnQuest operates the Sullom Voe Terminal ('SVT') on Shetland and around 1,000km of pipelines. Through the first half of 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. The SVT Power Station achieved 100% power delivery throughout the period.
EnQuest remains focused on right-sizing SVT for future operations and is progressing strategic projects to connect the terminal to the UK's electricity grid and to construct new stabilisation facilities ('NSF'). These projects have been undertaken to enable the Group to meet the North Sea Transition Authority ('NSTA') target of zero routine flaring obligations by 2030, and this is expected to result in a 90% reduction in overall emissions from SVT. The delivery of these projects will also reduce the Terminal's operating costs and provide resilience for long-term operations through the replacement of obsolete equipment. The projects provide the opportunity to extend SVT operations, which support production at both East of Shetland and West of Shetland assets.
EnQuest is also making progress with the phased decommissioning of the existing oil stabilisation, processing and storage facilities at the terminal. This is a significant step in effectively managing the integrity of the terminal infrastructure and creates the potential for its repurposing for new business development, including the new energy projects managed by Veri Energy.
Veri Energy
Electrification
During 2025, Veri Energy has worked on behalf of EnQuest to develop an onshore wind farm at the Sullom Voe Terminal. This project, which is expected to reach FID later this year, will harness Shetland's natural advantage of having one of the world's highest wind capacity factors and will utilise existing terminal infrastructure to assist in decarbonising and reducing costs at the site.
Carbon capture and storage ('CCS')
Veri Energy continues to develop a flexible, merchant-market carbon storage solution that can transport and permanently store CO2 from isolated emitters in the UK and Europe. CO2 captured by emitters will be transported via ship to SVT, from where it will be transported via repurposed pipeline infrastructure for permanent geological storage in depleted oil and gas reservoirs.
EnQuest holds two carbon storage licences, awarded as part of the first round of UK carbon sequestration licences issued by the North Sea Transition Authority ('NSTA'). The licence areas, CS013 and CS014, are some 99 miles northeast of Shetland and incorporate the Magnus and Thistle fields, both operated by EnQuest. These sites are large, well-characterised deep storage formations, which are connected by significant existing infrastructure to the Sullom Voe Terminal on Shetland.
Veri Energy's merchant model is designed to de-risk the CCS value chain, reducing the burden on government and emitters alike. By aligning commercial success with performance, rather than subsidy, Veri offers a cost-effective, market-led solution to carbon storage. It is disappointing, therefore, to note that the UK government does not plan any further investment in carbon storage beyond what was outlined in the most recent Comprehensive Spending Review. As it stands, this limits support to Track 1 projects, with only modest business development funding for Track 2. This approach negatively impacts the value proposition for emitters and is likely to see the UK ceding the opportunity to lead, despite possessing c.25% of Europe's total carbon storage capacity.
Veri Energy remains encouraged by the project's potential to provide a low-cost merchant-market solution for CO2 emitters to permanently sequester carbon. However, it is clear that a delay in government support will impact all UK projects of this type.
E-Fuels
Veri Energy continues to advance net-zero e-fuel production at SVT, focused on integrating green hydrogen and biogenic CO₂ to produce sustainable fuels. The initial target is to produce e-diesel for Shetland's marine and power sectors, with longer-term ambitions to scale into export markets, including sustainable aviation fuel ('SAF'). The combination of infrastructure, natural resources, and skilled labour makes SVT a compelling hub for low-carbon fuel production, and the Veri team continues to evaluate scenarios for end products, scale, partnerships and technology integration for the project.
Environmental, Social and Governance review
The health, safety and wellbeing of our people and delivering Safe Results is EnQuest's top priority. The Group has delivered three years of lost time incident ('LTI') free performance in Malaysia and was again presented with the HSE Excellence Award at the PETRONAS Emerald Awards in May. EnQuest's North Sea LTI performance has required additional focus, with leadership rolling out a 'prevention of personal injuries' campaign across the organisation and conducting a contractor HSE forum. The Group has a strong HSEA and process safety culture and is working with key contractors to ensure that all offshore personnel are committed to optimising safety performance.
EnQuest continues to make progress in reducing its absolute Scope 1 and 2 emissions and is leaving no stone unturned in efforts to deliver against national emissions reduction targets and the Board-approved net zero commitment. Since 2018, EnQuest's UK Scope 1 and 2 emissions have reduced by 40%, which is significantly ahead of the UK Government's North Sea Transition Deal target of achieving a 10% reduction in Scope 1 and 2 CO2 equivalent emissions by 2025 and close to the 50% reduction targeted by 2030. At SVT, EnQuest is progressing two projects which, together, will reduce terminal emissions by c.90%. The Group also plans to materially reduce the carbon footprint of the Kraken FPSO by replacing diesel fuel with a gas tie-back to Bressay and continually screens emission reduction opportunities at all sites.
In South East Asia, EnQuest sees a growth pathway that often aligns regional economic expansion with a country-level structural shortfall in energy supply. Natural gas is the transitional fuel that is bridging this gap at reduced emissions. EnQuest is therefore excited by the rapid growth that is delivering in its region, which the Group expects to further rebalance its carbon emissions.
Financial Review
All figures quoted are in US Dollars unless otherwise stated.
Overview
In H1 2025, strong uptime and a successful Magnus infill drilling campaign were offset by a third-party infrastructure outage that shut Magnus in for almost five weeks. This outage lowered Group H1 production by c.3,500 barrels per day, equivalent to the deferral of one cargo sale. Despite this, revenue and other operating income in the period fell by just c.6%; although cost of sales rose c.10%. EnQuest reported a pre-tax profit of $65.6 million (2024: $111.3 million).
Underlying these moves, a 14% decline in the Brent price was largely offset by the Group's active portfolio of hedging and a 37% rise in UK gas prices, with more third-party gas also crossing the Magnus field. Adjusting for these 'crossover' volumes, the benefit of which unwinds in cost of sales, Group operating costs were held flat - a significant achievement given that the USD weakened by 11% across the period. This robust performance was underpinned by EnQuest's focus on delivering safety-critical and production enhancing programmes of investment, which the Group delivers in a disciplined manner alongside an active programme of commodity and foreign exchange hedge programmes.
Post-tax, and as flagged in EnQuest's full year 2024 accounts, a $123.9 million non-cash adjustment due to the extension of the EPL 'windfall tax' by two years (from 31 March 2028 to 31 March 2030) distorts the H1 tax charge. Adjusting for this and other exceptional items, EnQuest reported a net loss of $43.1 million (2024: adjusted net profit of $84.2 million); which rises to a reported statutory net loss of $173.5 million when these items are included (2024: statutory net profit of $30.3 million).
Free Cash Flow in the period totalled $32.7 million (2024: $55.5 million) and at 30 June 2025, having paid a maiden dividend of c.$15 million, net debt totalled $376.6 million (31 December 2024 $385.8 million). Cash and undrawn facilities at the same date rose to $577.8 million (end 2024: $474.5 million), the Group's RBL capacity expanding by 34% following it's 1 January redetermination.
Post the balance sheet date, EnQuest paid $104.1 million in relation to the UK Energy Profits Levy, as well as the remaining $22.2 million completion payment associated with the Vietnam acquisition.
Having delivered a robust financial performance against a volatile macroeconomic and operational backdrop, EnQuest remains well positioned to deliver further material and value accretive growth transactions in both the UK and internationally.
Income statement
Revenue
Group production averaged 38,257 Boepd (10.6% lower than in H1 2024: 42,771 Boepd) with strong uptime performance of 89% across the operated portfolio, partially offset by lower Magnus production. Oil accounted for c.86% of this output (H1 2024: c.88%).
Brent crude oil prices declined 14.2% year-on-year, to average $71.8/bbl (H1 2024: $83.7/bbl) while the average day-ahead gas price rose 37.0% to 100p/therm (H1 2024: 73p/therm). Excluding the impact of hedging, EnQuest realised an average oil price of $70.8/bbl (H1 2024: $85.1/bbl). Post-hedging, the realised oil price was $71.0/bbl (14.9% lower than in H1 2024 ($83.4/bbl)).
Group revenue for H1 2025 totalled $549.1 million, a 6.3% reduction year-on-year (H1 2024: $586.0 million). Reflecting the above price and volume drivers, oil contributed $404.0 million (22.8% lower year-on-year, H1 2024: $523.1 million), and condensate and gas contributed $108.2 million (47.4% higher year-on-year, H1 2024: $73.4 million). Gas revenue mainly relates to the onward sale of gas purchases from third-party West of Shetland fields under the terms of the Magnus acquisition. The contribution of these volumes to revenue is offset through an equal and opposite charge to cost of sales. Tariffs and other income generated $2.8 million (H1 2024: $2.1 million), including income associated with the transportation of Seligi gas.
EnQuest benefited in the period from its steps in H2 2024 to reposition and expand its programme of hedging. Realised gains on commodity hedges totalled $1.0 million (2024: losses of $10.7 million). Unrealised gains on open commodity contracts (primarily from mark-to-market movements on swap contracts) totalled $33.2 million (2024: unrealised losses of $1.9 million).
For the period September to December 2025, the Group has c.1.6 MMbbls of production hedged, using swaps at an average price of $71/bbl. For 2026, EnQuest has a further c.4.2 MMbbls of production hedged, utilising swaps at an average price of $69/bbl, with an additional 0.1 MMbbls hedged using collars with a floor price of $53/bbl and ceiling price of $81/bbl.
Note: For the reconciliation of realised oil prices see 'Glossary - Non-GAAP measures' starting on page 31
Cost of sales1
Cost of sales were $388.9 million for the six months ended 30 June 2025 (10.4% higher than in H1 2024, $352.3 million). This increase was primarily driven by higher volumes and prices associated with third-party West of Shetland gas that crosses the Magnus facility (H1 2025: $96.4 million; H1 2024: $52.4 million). Excluding these 'crossover' gas volumes, cost of sales was 2.5% lower.
Operating costs of $182.8 million for H1 2025 were also marginally lower than H1 2024 ($183.0 million). A slight underlying increase in production costs was primarily driven by a weaker USD in the period, which was partially offset by foreign exchange hedging gains. On a unit basis, reflecting lower Magnus production volumes, operating costs averaged $26.4/Boe (2024: $23.5/Boe). Excluding foreign exchange hedge gains, unit operating costs were $27.8/Boe (2024: $22.8/Boe).
The credit relating to the Group's lifting position and hydrocarbon inventory for the six months ended 30 June 2025 was $1.5 million (H1 2024: credit of $22.8 million), primarily reflecting the timing of cargo liftings, while depletion expense ($124.0 million) was 9.3% lower than H1 2024 ($136.7 million), mainly reflecting lower production.
H1 2025 $ million
H1 2024 $ million
Production costs
156.4
143.6
Tariff and transportation expenses
36.0
34.0
Realised (gain)/loss on derivatives related to operating costs
(9.6)
5.4
Operating costs1
182.8
183.0
Credit relating to the Group's lifting position and hydrocarbon inventory
(1.5)
(22.8)
Other cost of operations
108.1
63.3
Depletion of oil and gas assets
124.0
136.7
Unrealised foreign exchange and UKA hedge (gains)/losses
(24.5)
(7.9)
Cost of sales
388.9
352.3
Unit operating cost1,2,3
$/Boe
$/Boe
- Production costs
22.6
18.4
- Tariff and transportation expenses
5.2
4.4
Average unit operating cost
27.8
22.8
Notes:
1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 31
2 Calculated using production on a working interest basis including Seligi Associated Gas
3 Excludes realised (gain)/loss on derivatives
Impairment
In the period, the Group recognised a non-cash net impairment reversal of $0.5 million (2024: charge of $21.0 million). This small net reversal represents a reversal of $49.4 million at Kraken and an aggregate charge of $48.9 million for GKA, Golden Eagle and Alba, and was primarily driven by a combination of a reduction in the discount rate to 9.5% (from 10.0% at 31 December 2024), changes in oil price assumptions (reflecting market dynamics) and updated production and cost profiles, including the impact of a weaker USD.
Other income and expenses1
The Group has recognised net other expense in the period of $18.0 million (2024: net expense of $29.1 million). A weaker US Dollar in H1 2025 resulted in a non-cash foreign exchange revaluation loss of $28.9 million (2024: $7.8 million foreign exchange revaluation gain) and a net increase in the decommissioning provision of fully impaired non-producing assets of $17.5 million (2024: non-cash charge of $4.9 million). These charges have been partially offset by: a net $14.9 million non-cash credit related to the aggregate change in fair value of Magnus contingent consideration (due to lower near-term oil price assumptions and production and cost profile changes (2024: $42.5 million non-cash expense driven by higher oil prices); lease income of $8.7 million (2024: $7.4 million) and $4.7 million provision release following resolution of the matter. Also included in H1 2024 were $1.6 million of insurance receipts, primarily related to the 2023 Kraken downtime.
Other expenses also include costs associated with Veri Energy, which in H1 2025 totalled $1.8 million (2024: $1.1 million).
Note:
1 Following a review of market practice, the unwinding of discount on the Magnus Contingent Consideration was reclassified in the 2024 Annual Report and Accounts to other income/expense from finance costs in the income statement to combine it with the other fair value movements, with comparative information restated. This restatement results in a $28.7 million charge for the six months ended 30 June 2024 being reclassified from finance costs to other income/expense.
Adjusted EBITDA
Adjusted EBITDA for the period totalled $234.6 million, which compares with $367.5 million in H1 2024. The year-on-year reduction predominantly reflects lower oil revenue due to lower oil prices and lower production due to Magnus third-party disruption.
EnQuest's net debt to last 12-month adjusted EBITDA ratio at 30 June 2025 equalled 0.7x (31 December 2024: 0.6x).
Adjusted EBITDA
H1 2025 $ million
H1 2024 $ million
Profit/(loss) from operations before tax and finance income/(costs)
138.7
179.9
Unrealised commodity hedge (gain)/loss
(33.2)
1.9
Depletion and depreciation
126.8
139.8
Impairment (reversal)/charge
(0.5)
21.0
Change in fair value of Magnus contingent consideration
(14.9)
42.5
Net other expense
12.8
3.3
Unrealised foreign exchange and UKA hedge (gains)/losses
(24.5)
(7.9)
Change in well inventories
0.5
(5.2)
Net foreign exchange loss/(gain)
28.9
(7.8)
Adjusted EBITDA1
234.6
367.5
Note:
1 See reconciliation of Adjusted EBITDA within the 'Glossary - Non-GAAP measures' starting on page 31
Finance costs
EnQuest's net finance costs were broadly flat, totalling $73.2 million (H1 2024: $68.6 million). This included an overall interest charge of $36.1 million (2024: $36.6 million) and financing fees of $6.1 million (2024: $5.7 million). Finance charges also included: the unwinding of discounting on decommissioning and other provisions of $17.0 million (2024: $13.7 million); lease liability interest costs of $11.4 million (2024: $16.6 million); and other financial expenses of $7.8 million (2024: $2.6 million), which are primarily comprised of the cost for surety bonds that provide security for decommissioning liabilities.
Finance income totalled $5.2 million (2024: $6.6 million), primarily representing interest on cash held on deposit.
Profit/loss before tax
Reflecting the movements above, the Group's profit before tax was $65.6 million (2024: profit of $111.3 million).
Taxation
As previously highlighted in the Group's 2024 Annual Report and Accounts, the 2025 half year tax charge of $239.1 million has been heavily distorted by the $123.9 million non-cash deferred tax impact from the two-year extension to the EPL, which was enacted in H1 2025. Other non-cash deferred tax charges totalled $65.4 million and these largely reflect the utilisation of EnQuest's strategic UK North Sea tax asset in the period and tax on unrealised hedge gains.
As a result, just 20.8% of the Group income statement reported tax charge relates to current cash tax charge, totalling $49.8 million, of which $45.2 million relates to the EPL (2024: $41.1 million of which $34.1 million was EPL related).
Inclusive of the one-off charge, the Group's overall effective tax rate in the period equalled 364.6% (period ended 30 June 2024: 72.7%), with the two-year extension to the EPL accountable for 188.9% of the rate.
EnQuest's strategic UK North Sea tax asset was estimated at $1,978.3 million at 30 June 2025 (31 December 2024: $2,066.4 million).
Reflecting the Group's tax position, no significant corporation tax or supplementary charge is expected to be paid on UK operational activities for the foreseeable future. The Group expects to continue to make EPL payments for the duration of the levy, and EnQuest also pays cash corporate income tax on its Malaysian assets.
Profit/loss for the period
Looking through the one off $123.9 million non-cash deferred tax charge described above and other exceptional items, EnQuest delivered an adjusted net loss of $43.1 million (2024: adjusted net profit of $84.2 million). This rises to a statutory net loss of $173.5 million on inclusion of these charges (2024: statutory net profit of $30.3 million).
Earnings per share
The Group's reported basic loss per share was 9.3 cents (2024: earnings of 1.6 cents) and reported diluted loss per share was 9.3 cents (2024: earnings of 1.6 cents).
Cash flow, EnQuest net debt and liquidity
Due to lower oil prices and the five-week shut-in of Magnus, reported net cash flows from operating activities for the period were $191.9 million (H1 2024: $323.4 million).
Reported net cash flows used in investing activities increased year-on-year by $53.7 million, to $83.8 million. Whilst this figure includes the "one-off" impact from the payment of a $3.6 million deposit in relation to the Vietnam asset acquisition, the H1 2024 comparator ($30.1 million) included "one-off" receipts associated with the Bressay transaction of $108.8 million.
Excluding these impacts, net cash flows used in investing activities decreased by $58.7 million - largely as a result of there being no Magnus profit share payments in H1 2025 (H1 2024: $48.1 million) and $11.8 million lower capital expenditures.
Cash outflow on capital expenditure is set out in the table below:
Capital expenditure
H1 2025 $ million
H1 2024 $ million
North Sea
70.3
84.4
Malaysia
11.5
9.3
Exploration and evaluation
1.4
1.3
83.2
95.0
The Group utilised $73.3 million of cash in financing activities (2024: $266.3 million). In June 2025, EnQuest paid a dividend equivalent to $15.3 million, while interest payments on the Group's borrowings totalled $43.6 million (H1 2024: $44.0 million). $35.4 million was paid in relation to finance leases (H1 2024: $85.0 million), with the reduction versus 2024 primarily reflecting the c.70% contractual step down in charges relating to the Kraken FPSO. During H1 2025, the Group borrowed a net $21.0 million, primarily from the vendor loan facility, while H1 2024 included net repayments of the Group's loans and borrowings totalling $134.8 million.
In aggregate, EnQuest's cash and cash equivalents increased by $50.5 million in the first half of 2025. This increase was primarily driven by adjusted free cash flow generation of $32.7 million and the favourable impact of a weaker USD on the value of GBP deposits. Adjusted free cash flow generation in the first half of 2025 was lower than the same period in 2024, reflecting lower oil revenues offset by a reduction in lease payments, no Magnus profit share payment and lower capital expenditure.
The movement in EnQuest net debt was as follows:
$ million
EnQuest net debt 1 January 2025
(385.8)
Net cash flows from operating activities
191.9
Cash capital expenditure
(83.2)
Net interest and finance costs paid
(40.6)
Finance lease payments
(35.4)
Dividend paid
(15.3)
Acquisition costs
(3.6)
Other movements, primarily net foreign exchange on cash and debt
(4.6)
EnQuest net debt 30 June 20251
(376.6)
Note:
1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 31.
EnQuest ended the period with $330.7 million of cash and cash equivalents (31 December 2024: $280.2 million), while cash and available undrawn facilities at 30 June 2025 totalled $577.8 million (31 December 2024: $474.5 million).
Net Debt
30 June 2025 $ million
31 December 2024 $ million
Bonds
647.8
632.1
SVT Working Capital Facility
37.0
33.9
Vendor loan facility
22.5
-
Cash and cash equivalents
(330.7)
(280.2)
EnQuest net debt1
376.6
385.8
Note:
1 See reconciliation of EnQuest net debt within the 'Glossary - Non-GAAP measures' starting on page 31
Balance sheet
EnQuest's robust liquidity position enables the Group to continue delivering its capital-efficient programmes of investment and pursue transformational North Sea and International asset acquisitions. EnQuest remains committed to maintaining a strong and flexible balance sheet through a proactive and disciplined approach to capital management. As part of its ongoing financial strategy, the Group continues to carefully monitor the broader debt capital markets in relation to both its RBL and bond maturities.
Assets
Total assets at 30 June 2025 increased by 2.6% to $3,654.2 million (31 December 2024: $3,562.6 million). Driving this were: higher cash and cash equivalents of $50.5 million; an increase of $42.2 million in other current financial assets including the closing mark-to-market valuation of the Group's open swaps and foreign exchange contracts; and $28.3 million higher trade and other receivables; partially offset by a $55.8 million lower deferred tax asset reflecting the utilisation of losses.
Liabilities
Total liabilities increased by 9.3% to $3,300.4 million (31 December 2024: $3,020.1 million) reflecting: higher tax liabilities of $193.8 million, primarily reflecting the impact on deferred tax from the 2-year extension to the UK EPL and income tax accrued on H1 2025 profits; an increase in provisions of $40.6 million, driven mainly by the impact of a weaker USD on the decommissioning provision and an increase in loans and borrowings of $44.0 million, including a drawdown on a vendor loan facility and the impact of a weaker USD on the GBP retail bond value.
The net change in the fair value estimate of the contingent consideration (related to the acquisition of Magnus) drove a lower outstanding estimate of $457.8 million (31 December 2024: $473.3 million). There were no profit share payments made during the period.
Total income tax liabilities, excluding deferred tax, increased by $60.3 million in the period to $162.2 million (31 December 2024: $101.9 million), with $119.8 million in current liabilities and $42.4 million in non-current liabilities.
Financial risk management
The Group's activities expose it to various financial risks particularly associated with fluctuations in oil price, foreign currency risk, liquidity risk and credit risk. The disclosures in relation to financial risk management objectives and policies, including the policy for hedging, and the disclosures in relation to exposure to oil price, foreign currency and credit and liquidity risk, are included in note 27 of the Group's 2024 Annual report.
Going concern disclosure
In the first half of 2025 EnQuest has continued to focus on deleverage, optimisation of its capital structure and the maximisation of its available transactional capacity. Recent business development activities, principally undertaken in Asia, have added near-term production, reserves and strengthened future Group cash flow generation.
Despite lower oil prices and third-party disruption to Magnus production, EnQuest delivered adjusted free cash flow in the first half of 2025 that funded the Group's dividend and reduced Group net debt to $376.6 million at 30 June 2025. EnQuest also ended the period with cash and available facilities of $577.8 million. From this robust position, in July, the Group paid $104.1 million in relation to the UK Energy Profits Levy, as well as the remaining $22.2 million completion payment associated with the Vietnam acquisition.
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.
The Group's latest approved business plan underpins management's base case ('Base Case'). It is in line with EnQuest's production guidance (including the acquisition and contribution of the Block 12W in Vietnam following completion on 9 July 2025) and an oil price assumption of $67.0/bbl is used for the remainder of 2025 and 2026.
A reverse stress test has been performed on the Base Case. This indicates that an oil price of c.$40.0/bbl is required to maintain covenant compliance over the going concern period. The low level of this required price reflects the Group's strong liquidity position.
The Base Case has also been subjected to further testing through a scenario that explores the impact of the following plausible downside risks (the 'Downside Case'):
· 10.0% discount to Base Case prices, resulting in Downside Case prices of $60.3/bbl for the remainder of 2025 and 2026;
· Production risking of 5.0%; and
· 2.5% increase in operating costs.
The Base Case and Downside Case indicate that the Group is able to operate as a going concern and remain covenant compliant for 12 months from the date of publication of its half-year results.
After making appropriate enquiries and assessing the progress against the forecast, the Directors have a reasonable expectation that the Group will continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing these financial statements.
Risks and uncertainties
During the year, an in-depth review of the principal risks facing the Company has been undertaken. During this review, the Directors have concluded the majority of the principal risks for the remaining six months of the financial year are unchanged from those described in the 2024 Annual Report and Accounts, which was published in April 2025. However, certain risks have been amended to more accurately capture the underlying risk while others are no longer considered principal in nature but remain part of the Group's wider risk universe and will continue to be monitored. To reach this conclusion, the Directors considered the changes in the external environment during the recent period that could threaten the Company's business model, future performance, liquidity, and reputation. The Directors also considered management's view of the current risks facing the Company.
Accordingly, for the purposes of meeting the disclosure requirements of DTR 4.2.7(2), the Board believes that the Group's principal risks and uncertainties for the remaining six months are:
Principal risks and uncertainties
· Health, Safety and Environment ('HSE')
· Oil and gas development, production and exploration activities are by their very nature complex, with HSE risks covering many areas, including major accident hazards, personal health and safety, compliance with regulatory requirements, asset integrity issues and potential environmental impacts, including those associated with climate change.
· Prices and foreign exchange (previously "Oil and gas prices")
· A material decline in oil and gas prices adversely affects the Group's operations and financial condition as the Group's revenue depends substantially on oil prices. This risk also includes the potential impacts of climate change on oil and gas supply and demand and recognises that other macroeconomic factors, such as FX and carbon pricing, could present a material risk to the business.
· Production
· The Group's production is critical to its success and is subject to a variety of risks, including: subsurface uncertainties; the complexities of operating in a mature field environment; potential for significant unexpected shutdowns; and unplanned expenditure (particularly where remediation may be dependent on suitable weather conditions offshore).
· Lower than expected reservoir performance or insufficient addition of new resources may have a material impact on the Group's future growth.
· Longer‑term production is threatened if low oil prices or prolonged field shutdowns and/or underperformance requiring high‑cost remediation bring forward decommissioning timelines.
· Access to capital and liquidity (previously "Financial")
· Inability to fund financial commitments or maintain adequate cash flow and liquidity and/or reduce costs.
· Significant reductions in the oil price, production and/or the funds available under the Group's reserve based lending ('RBL') facility, and/or further changes in the UK's fiscal environment, will likely have a material impact on the Group's ability to invest in its asset base and repay or refinance its existing credit facilities. Prolonged low oil prices, cost increases (including those related to an environmental incident), and production delays or outages, could threaten the Group's liquidity and/or ability to comply with relevant covenants.
· IT security and resilience
· The Group is exposed to risks arising from interruption to, or failure of, IT infrastructure. The risks of disruption to normal operations range from loss in functionality of generic systems (such as email and internet access) to the compromising of more sophisticated systems that support the Group's operational activities. These risks could result from malicious interventions such as cyber-attacks or phishing exercises.
· Reserves estimation and replacement
· Failure to develop the Group's contingent and prospective resources or secure new licences and/or asset acquisitions and realise their expected value.
· Project execution and delivery
· The Group's success will be partially dependent upon the successful execution and delivery of potential future projects that are undertaken, including decommissioning, decarbonisation and new energy opportunities in the UK.
· Political, regulatory and fiscal environment (previously "Fiscal risk and government take")
· Unanticipated changes in the political, regulatory or fiscal environment, including those associated with climate change, can affect the Group's ability to deliver its strategy/business plan and potentially impact revenue and future developments.
The risks that are no longer considered principal in nature are: Competition; Portfolio Concentration; International Business; JV Partners; Reputation; and Human Resources.
Group Income Statement
For the six months ended 30 June 2025
30 June 2025
30 June 2024
Notes
$'000 Unaudited
$'000 Unaudited
Revenue and other operating income
4
549,122
586,020
Cost of sales
(388,935)
(352,310)
Gross profit
160,187
233,710
Net impairment reversal/(charge) to oil and gas assets
7
532
(20,995)
General and administration expenses
(3,945)
(3,695)
Other expenses
(18,046)
(29,136)
Profit/(loss) from operations before tax and finance income/(costs)
138,728
179,884
Finance costs
(78,371)
(75,195)
Finance income
5,220
6,589
Profit/(loss) before tax
65,577
111,278
Income tax expense(i)
5
(239,079)
(80,930)
(Loss)/profit for the period attributable to owners of the parent
(173,502)
30,348
Total comprehensive (loss)/profit for the period, attributable to owners of the parent
(173,502)
30,348
There is no comprehensive income attributable to the shareholders of the Group other than the loss for the period. Revenue and operating profit are all derived from continuing operations.
(Loss) / Earnings per share
6
$
$
Basic
(0.093)
0.016
Diluted
(0.093)
0.016
The attached notes 1 to 15 form part of these condensed Group financial statements.
(i) Inclusive of a deferred tax charge of $189.3 million (2024: $39.9 million) which includes a $123.9 million impact from the two-year extension to the UK Energy Profits Levy enacted in March 2025 (2024: nil)
Group Balance Sheet
At 30 June 2025
Notes
30 June 2025 $'000
31 December 2024 $'000
Unaudited
Audited
ASSETS
Non-current assets
Property, plant and equipment
7
2,313,187
2,297,954
Goodwill
134,400
134,400
Intangible assets
22,529
20,563
Deferred tax assets
5
450,678
506,481
Trade and other receivables
1,462
2,102
Other financial assets
9
43,449
38,459
2,965,705
2,999,959
Current assets
Intangible assets
954
1,138
Inventories
55,257
48,976
Trade and other receivables
259,261
230,971
Current tax receivable
5
-
1,256
Cash and cash equivalents
330,730
280,239
Other financial assets
9
42,322
69
688,524
562,649
TOTAL ASSETS
3,654,229
3,562,608
EQUITY AND LIABILITIES
Equity
Share capital and premium
392,054
392,054
Treasury shares
(4,425)
(4,425)
Share-based payments reserve
14,067
13,949
Capital redemption reserve
2,006
2,006
Retained (deficit)/earnings
(49,920)
138,882
TOTAL EQUITY
353,782
542,466
Non-current liabilities
Loans and borrowings
8
639,233
621,440
Lease liabilities
272,299
288,262
Contingent consideration
10
446,229
452,891
Provisions
11
752,919
710,976
Deferred income
138,095
138,095
Tax payable
5
42,425
-
Deferred tax liabilities
5
238,146
104,698
2,529,346
2,316,362
Current liabilities
Loans and borrowings
8
69,591
43,417
Lease liabilities
74,203
46,994
Contingent consideration
10
11,551
20,403
Provisions
11
53,767
55,130
Trade and other payables
436,089
414,390
Other financial liabilities
9
6,141
21,580
Current tax payable
5
119,759
101,866
771,101
703,780
TOTAL LIABILITIES
3,300,447
3,020,142
TOTAL EQUITY AND LIABILITIES
3,654,229
3,562,608
The attached notes 1 to 15 form part of these condensed Group financial statements.
Group Statement of Changes in Equity
For the six months ended 30 June 2025
Share capital $'000
Share premium $'000
Treasury shares $'000
Share-based payments reserve $'000
Capital redemption reserve $'000
Retained (deficit)/earnings $'000
Total $'000
Unaudited
Unaudited
Unaudited
Unaudited
Unaudited
Unaudited
Unaudited
Balance at 1 January 2024
133,285
260,546
-
13,195
-
49,702
456,728
Profit for the period
-
-
-
-
-
30,348
30,348
Total comprehensive profit for the period
-
-
-
-
-
30,348
30,348
Issue of shares to Employee Benefit Trust
229
-
-
(229)
-
-
-
Share-based payment
-
-
-
894
-
-
894
Repurchase of shares
-
-
(2,479)
-
-
-
(2,479)
Balance at 30 June 2024
133,514
260,546
(2,479)
13,860
-
80,050
485,491
Balance at 1 January 2025
131,508
260,546
(4,425)
13,949
2,006
138,882
542,466
Loss for the period
-
-
-
-
-
(173,502)
(173,502)
Total comprehensive loss for the period
-
-
-
-
-
(173,502)
(173,502)
Share-based payment
-
-
-
118
-
-
118
Dividend paid
-
-
-
-
-
(15,300)
(15,300)
Balance at 30 June 2025
131,508
260,546
(4,425)
14,067
2,006
(49,920)
353,782
The attached notes 1 to 15 form part of these condensed Group financial statements.
Group Statement of Cash Flows
For the six months ended 30 June 2025
Notes
30 June 2025 $'000
30 June 2024 $'000
Unaudited
Unaudited
CASH FLOW FROM OPERATING ACTIVITIES
Cash generated from operations
13
215,224
368,872
Cash (paid)/received on (purchase)/sale of financial instruments
(1,900)
(6,588)
Decommissioning spend
(31,387)
(31,516)
Net cash received/(paid) for trading/purchase of other intangible assets
12,003
(321)
Cash paid to settle provision
(3)
-
Income taxes (paid)/received
(1,989)
(7,029)
Net cash flows from/(used in) operating activities
191,948
323,418
INVESTING ACTIVITIES
Purchase of property, plant and equipment
(81,252)
(93,629)
Purchase of intangible oil and gas assets
(1,966)
(1,362)
Payment of Magnus contingent consideration - Profit share
10
-
(48,118)
Acquisition Deposit
(3,550)
-
Vendor financing facility receipt
-
107,518
Proceeds from farm-down
-
1,263
Interest received
2,992
4,181
Net cash flows (used in)/from investing activities
(83,776)
(30,147)
FINANCING ACTIVITIES
Proceeds from loans and borrowings
27,420
19,735
Repayment of loans and borrowings
(6,451)
(154,528)
Payment of obligations under financing leases
(35,441)
(85,020)
Interest paid
(43,554)
(43,975)
Payment for repurchase of shares
-
(2,479)
Dividend paid
14
(15,300)
-
Net cash flows (used in)/from financing activities
(73,326)
(266,267)
NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS
34,846
27,004
Net foreign exchange on cash and cash equivalents
15,645
(3,257)
Cash and cash equivalents at 1 January
280,239
313,572
CASH AND CASH EQUIVALENTS AT 30 JUNE
330,730
337,319
Reconciliation of cash and cash equivalents
Total cash at bank and in hand
260,020
327,848
Restricted cash(i)
70,710
9,471
Cash and cash equivalents per balance sheet
330,730
337,319
(i) At 30 June 2025, restricted cash represents $53.5 million placed in escrow accounts for 2025 Decommissioning Security Agreement obligations (31 December 2024: $53.4 million), $15.4 million for cash collateralised Letters of Credit (31 December 2024: nil) and $1.8 million related to the deposit of a Performance Bond in Indonesia (31 December 2024: nil). 30 June 2024 represents $1.0 million on deposit relating to bank guarantees for the Group's Malaysian assets and $8.4 million held in escrow in relation to a dispute with a third-party contractor
The attached notes 1 to 15 form part of these condensed Group financial statements.
Notes to the Half Year Condensed Financial Statements
For the period ended 30 June 2025
1. Corporate information
EnQuest PLC ('EnQuest' or the 'Company') is a public company limited by shares incorporated in the United Kingdom under the Companies Act and is registered in England and Wales and listed on the London Stock Exchange.
The principal activities of the Company and its subsidiaries (together the 'Group') are to responsibly optimise hydrocarbon production, leverage existing infrastructure, deliver a strong decommissioning performance and explore new energy and decarbonisation opportunities. The Group's half year condensed financial statements for the six months ended 30 June 2025 were authorised for issue in accordance with a resolution of the Board of Directors on 23 September 2025.
2. Basis of preparation
The interim condensed consolidated financial statements of the Group for the six months ended 30 June 2025 have been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted by the UK. The presentation currency of the Group financial information is US Dollars and all values in the Group financial information are rounded to the nearest thousand ($'000) except where otherwise stated.
The interim report does not include all the information and disclosures required in the annual financial statements and should be read in conjunction with the Group's annual financial statements for the year ended 31 December 2024.
The financial information contained in this announcement does not constitute statutory financial statements within the meaning of section 434 of the Companies Act 2006.
Consolidated statutory accounts for the year ended 31 December 2024, on which the auditor gave an unqualified audit report, have been filed with the Registrar of Companies.
During the preparation of the statutory accounts for the year ended 31 December 2024, the Group removed the separate disclosure of remeasurements and exceptional items from the presentation of the Group income statement to simplify their presentation for users of accounts and bring them more in line with peers. This presentation has also been applied to these half year condensed financial statements, including the comparative figures for the six months ended 30 June 2024. The Group continues to present various Alternative Performance Measures ('APMs') when assessing and discussing the Group's financial performance, balance sheet and cash flows that are not defined or specified under IFRS but consistent with the measurement basis applied to the financial statements. The Group uses these APMs, which are not considered to be a substitute for, or superior to, IFRS measures, to provide stakeholders with additional useful information to aid the understanding of the Group's underlying financial performance, balance sheet and cash flows by adjusting for certain items, such as those previously classified as remeasurements and exceptional items, which impact upon IFRS measures or, by defining new measures. See the Glossary - Non-GAAP Measures on page 31 for more information.
The financial statements have been prepared on the going concern basis. Further information relating to the use of the going concern assumption is provided in the 'Going Concern' section of the Financial Review as set out on page 11. The interim financial statements have been reviewed by the auditor and its report to the Company is included within these interim financial statements.
Accounting policies
The accounting policies adopted in the preparation of the interim condensed financial statements for the six months ended 30 June 2025 are materially consistent with those followed in the preparation of the Group's financial statements for the year ended 31 December 2024. Any other standard, interpretation or amendment that was issued but not yet effective has not been adopted by the Group.
Critical accounting judgements and key sources of estimation uncertainty
Critical accounting judgements and key sources of estimation uncertainty were disclosed in the Group's 2024 annual report and accounts. These are reconsidered at the end of each reporting period to determine if any changes are required to judgements and estimates as a result of current market conditions. Key changes from those judgements and estimates disclosed in the Group's 2024 annual report and accounts are set out below:
Recoverability of asset carrying values - oil price
The Group's un-hedged Brent oil price assumption was revised during the first half of 2025. The Group's Brent assumptions for the remainder of 2025 and 2026 have changed to reflect the decrease in oil prices in the first half of 2025, following macroeconomic volatility and OPEC's decision to unwind voluntary production cuts. The assumption for 2027 and the Group's longer term Brent price assumption is unchanged from that disclosed in the Group's 2024 annual report and accounts. See the table below for summary of oil price assumptions used at 30 June 2025. The price assumptions used at the end of 2024 were $75.0/bbl (2025), $75.0/bbl (2026), $75.0/bbl (2027) and inflated at 2% per annum from 2028. See note 7 for oil price sensitivities.
Second half 2025
2026
2027
2028>*
Brent oil ($/bbl)
70.0
70.0
75.0
77.0
*Inflated at 2% from 2028
Discount rates - Impairment
The WACC rate applied to discount the future cash flows for calculating the cash generating unit ('CGU') fair value less costs to dispose for impairment purposes was reassessed. Reflecting the Group's expanded portfolio, strong liquidity position and increased lender appetite for deploying capital in energy assets, the rate has been reduced to 9.5% at 30 June 2025 (December 2024: 10.0%). See note 7 for related sensitivity analysis.
New and amended standards adopted by the Group
The following new standards became applicable for the current reporting period. No material impact was recognised upon application.
Amendments to IAS 21
Lack of exchangeability
3. Segment information
Segment information for the six month period is as follows:
Period ended 30 June 2025 $'000
North Sea
Malaysia
All other segments
Total segments
Adjustments and eliminations(i), (iii)
Consolidated
Revenue and other operating income:
Revenue from contracts with customers
459,029
54,858
-
513,887
-
513,887
Other operating income/(expense) (i)
901
-
108
1,009
34,226
35,235
Total revenue and other operating income/(expense)
459,930
54,858
108
514,896
34,226
549,122
Segment profit/(loss) before tax and finance income/(costs)(ii)(iii)
53,155
18,867
(1,557)
70,465
68,263
138,728
Periodended 30 June 2024 $'000
North Sea
Malaysia
All other segments
Total segments
Adjustments and eliminations(i), (ii)
Consolidated
Revenue and other operating income:
Revenue from contracts with customers
533,371
64,293
-
597,664
-
597,664
Other operating income/(expense)(i)
810
-
122
932
(12,576)
(11,644)
Total revenue and other operating income/(expense)
534,181
64,293
122
598,596
(12,576)
586,020
Segment profit/(loss) before tax and finance income/(costs)(ii)(iii)
164,186
24,492
1,344
190,022
(10,138)
179,884
(i) Finance income and costs and gains and losses on derivatives are not allocated to individual segments as the underlying instruments are managed on a Group basis
(ii) Tax is not included as this is not disclosed to the Chief Operating Decision Maker within the segment profit/(loss)
(iii) Inter-segment revenues are eliminated on consolidation. All other adjustments are part of the reconciliations presented further below
Reconciliation of profit/(loss):
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Total segments profit/(loss) before tax and finance income/(costs)
70,465
190,022
Finance income
5,220
6,589
Finance expense
(78,371)
(75,195)
Gain/(loss) on derivatives(i)
68,263
(10,138)
Profit/(loss) before tax
65,577
111,278
(i) Includes $10.6 million realised gains (2024: $16.1 million realised losses) on derivatives and $57.7 million unrealised gains (2024: $5.9 million unrealised gains) on derivatives
4. Revenue and other operating income
The Group generates revenue through the sale of crude oil, gas and condensate to third parties, and through the provision of infrastructure to its customers for tariff income. Further details are described in the last annual financial statements.
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Revenue from contracts with customers:
Revenue from crude oil sales
403,965
523,065
Revenue from gas and condensate sales(i)
108,180
73,449
Tariff revenue
1,742
1,150
Total revenue from contracts with customers
513,887
597,664
Realised gains/(losses) on commodity derivative contracts
1,019
(10,664)
Unrealised gains/(losses) on commodity derivative contracts
33,207
(1,912)
Other
1,009
932
Total revenue and other operating income
549,122
586,020
(i) Includes onward sale of third-party gas purchases not required for injection activities at Magnus. See Operating costs reconciliation within Non-GAAP measures on page 31
5. Income tax
The major components of income tax expense/(credit) are as follows:
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Current overseas income tax
Current income tax charge
4,585
7,019
UK Energy Profits Levy
Current year charge
42,425
33,530
Adjustments in respect of current charge of previous years
2,818
530
Total current income tax
49,828
41,079
Deferred UK income tax
Relating to origination and reversal of temporary differences
56,262
68,385
Adjustments in respect of deferred income tax of previous years
(460)
(8,178)
Deferred overseas income tax
Relating to origination and reversal of temporary differences
3,280
1,206
Deferred UK Energy Profits Levy
Relating to origination and reversal of temporary differences
130,142
(23,241)
Adjustments in respect of deferred charge of previous years
27
1,679
Total deferred income tax
189,251
39,852
Income tax expense reported in profit or loss
239,079
80,930
(b) Reconciliation of total income tax charge
A reconciliation between the income tax charge and the product of accounting profit multiplied by the UK statutory tax rate is as follows:
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Profit/(loss) before tax
65,577
111,278
UK statutory tax rate applying to North Sea oil and gas activities of 40% (2024: 40%)
Deferred tax asset not recognised in respect of non-ring-fence trade
12,541
6,416
UK Energy Profits Levy(ii)
48,692
10,289
UK Energy Profits Levy - extension to March 2030(iii)
123,875
-
Adjustments in respect of prior years
2,385
(5,969)
Overseas tax rate differences
(566)
2,576
Share-based payments
(1,856)
(473)
Other differences
11,787
5,540
At the effective income tax rate of 365% (2024: 73%)
239,079
80,930
(i) Predominantly in relation to non-deductible foreign exchange on EPL tax liabilities and non-qualifying expenditure relating to the initial recognition exemption utilised under IAS 12 upon acquisition of Golden Eagle given that at the time of the transaction, it affected neither accounting profit nor taxable profit
(ii) Total current period EPL charge only, with 2025 impacted by the higher rate of 38% (2024: 35%) and the removal of investment allowances. This charge consists of an EPL current tax charge of $42.4 million (30 June 2024: $33.5 million charge) and deferred EPL charge of $6.3 million (30 June 2024: $23.2 million credit).
(iii) Reflects the impact of the substantively enacted two-year extension referred to in part (e) below
(c) Deferred income tax
Deferred income tax relates to the following:
Group balance sheet
Charge/(credit) for the six months ended 30 June recognised in profit or loss
30 June 2025 $'000
31 December 2024 $'000
2025 $'000
2024 $'000
Deferred tax liability
Accelerated capital allowances
1,028,112
911,501
116,611
(824)
1,028,112
911,501
Deferred tax asset
Losses
(668,563)
(717,900)
49,337
41,248
Decommissioning liability
(282,751)
(263,705)
(19,046)
(5,551)
Other temporary differences(i)
(289,330)
(331,679)
42,349
4,979
(1,240,644)
(1,313,284)
189,251
39,852
Net deferred tax (assets)(ii)
(212,532)
(401,783)
Reflected in the balance sheet as follows:
Deferred tax assets
(450,678)
(506,481)
Deferred tax liabilities
238,146
104,698
Net deferred tax (assets)
(212,532)
(401,783)
(i) Predominantly includes $198.5 million related to Magnus acquisition contingent consideration in note 10 and $107.7 million on deferred income (see note 24 in the Group's 2024 Annual Report and Accounts). The remaining net liability balance in Other temporary differences of $16.9 million is largely related to a liability associated with unrealised hedging gains and an asset associated with deferred PRT
(ii) The total amounts for EPL included in net deferred assets are a deferred tax liability of $275.5 million for accelerated capital allowances and a deferred tax asset of $58.1 million for other items, which predominantly includes $25.3 million related to Magnus acquisition contingent consideration (note 10) and $52.5 million related to deferred income (see note 24 in the Group's 2024 Annual Report and Accounts). The remaining liability balance for other items of $19.7 million arises largely in respect of unrealised hedging gains
Reconciliation of net deferred tax assets/(liabilities)
30 June 2025 $'000
31 December 2024 $'000
At beginning of period
401,783
462,479
Tax expense during the period recognised in profit or loss
(189,251)
(60,696)
At end of period
212,532
401,783
(d) Tax losses
The Group's deferred tax assets at 30 June 2025 are recognised to the extent that taxable profits are expected to arise in the future against which tax losses and allowances in the UK can be utilised.
EnQuest has c.$3 billion of cumulative gross UK ring-fence tax losses. As at 30 June 2025, the Group had a balance of $1,978.3 million gross ring-fence tax losses for which a deferred tax asset has been recognised (31 December 2024: $2,066.4 million), and $1,117.5 million (31 December 2024: $1,117.5 million) associated with EnQuest Progress Limited for which no deferred tax asset has been recognised as recovery of these losses is yet to be established. In addition, the Group has unused UK mainstream corporation tax losses of $541.1 million (31 December 2024: $496.1 million) for which a deferred tax asset has not been recognised and has also not recognised a deferred tax asset for the adjustment to bond valuations on the adoption of IFRS 9. The benefit of this bond deduction is taken over ten years, with a deduction of $1.0 million being taken in the current period and the remaining benefit of $5.3 million (31 December 2024: $6.3 million) remaining unrecognised. The Group has unused Malaysian income tax losses of $15.9 million (31 December 2024: $14.7 million) arising in respect of the Tanjong Baram RSC for which no deferred tax asset has been recognised at the balance sheet date due to uncertainty of recovery of these losses.
In accordance with IAS 12 Income Taxes, the Group assesses the recoverability of its recognised deferred tax assets (as set out in the table above) at each period end. Sensitivities have been run on the oil price assumption, with a 10% change being considered a reasonable possible change for the purposes of sensitivity analysis (see note 2). A 10% reduction in oil price would result in a deferred tax asset derecognition of $37.5 million while a 10% increase in oil price would not result in any change as the Group is currently recognising a deferred tax asset associated with all UK ring-fence tax losses (with the exception of those noted above).
No deferred tax has been provided on unremitted earnings of overseas subsidiaries. The Finance Act 2009 exempted foreign dividends from the scope of UK corporation tax where certain conditions are satisfied.
(e) Changes in legislation
On 29 July 2024, the UK Government announced various changes to the EPL including an extension to 31 March 2030 (previously 31 March 2028) to which the EPL applies. This extension was substantively enacted on 3 March 2025, with the impact on the current period financial statements tax charge and deferred tax for EPL being $123.9 million.
6. Earnings per share
The calculation of earnings per share is based on the profit after tax and on the weighted average number of Ordinary shares in issue during the period. Diluted earnings per share is adjusted for the effects of Ordinary shares granted under the share-based payment plans, which are held in the Employee Benefit Trust, unless it has the effect of increasing the profit or decreasing the loss attributable to each share.
At 30 June 2025, the Group held 25,000,000 (30 June 2024: 13,938,021) shares which have been classed in the balance sheet as Treasury shares. These Treasury shares have been excluded for the purposes of calculating the basic and diluted earnings per share at 30 June 2025.
Basic and diluted earnings per share are calculated as follows:
Profit/(loss) after tax
Weighted average number of Ordinary shares
(Loss) / Earnings per share
Period ended 30 June
Period ended 30 June
Period ended 30 June
2025 $'000
2024 $'000
2025 million
2024 million
2025 $
2024 $
Basic
(173,502)
30,348
1,859.5
1,895.7
(0.093)
0.016
Dilutive potential of Ordinary shares granted under share-based incentive schemes
-
-
40.0
38.2
-
-
Diluted(i)
(173,502)
30,348
1,899.5
1,933.9
(0.093)
0.016
(i) Potential ordinary shares granted under share-based incentive schemes are not treated as dilutive when they would decrease a loss per share
7. Property, plant and equipment
Oil and gas assets $'000
Office furniture, fixtures and fittings $'000
Right-of-use assets $'000
Total $'000
Cost:
At 1 January 2025
9,568,879
68,972
921,447
10,559,298
Additions
80,098
144
28,291
108,533
Change in decommissioning provision
32,982
-
-
32,982
At 30 June 2025
9,681,959
69,116
949,738
10,700,813
Accumulated depreciation, depletion and impairment:
At 1 January 2025
7,651,364
61,997
547,983
8,261,344
Charge for the period
98,078
1,067
27,669
126,814
Net impairment charge/(reversal)
14,513
-
(15,045)
(532)
At 30 June 2025
7,763,955
63,064
560,607
8,387,626
Net carrying amount:
At 30 June 2025
1,918,004
6,052
389,131
2,313,187
At 31 December 2024
1,917,515
6,975
373,464
2,297,954
At 30 June 2024
1,886,738
7,964
403,285
2,297,987
Impairments
Impairments to the Group's producing assets and reversals of impairments are set out in the table below:
Impairment reversal/(charge)
Recoverable amount(i)
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Period ended 30 June 2025 $'000
Year ended 31 December 2024 $'000
North Sea
532
(20,995)
1,144,727
1,172,487
Net pre-tax impairment charge
532
(20,995)
(i) Recoverable amount has been determined on a fair value less costs of disposal basis. The amounts disclosed above are in respect of assets where an impairment (or reversal) has been recorded. Assets which did not have any impairment or reversal are excluded from the amounts disclosed
The 1H 2025 net impairment reversal of $0.5 million relates to producing assets in the UK North Sea and is primarily driven by a reduction in the discount rate to 9.5% (from 10.0% at 31 December 2024), a reduction in short-term (2H 2025 and 2026) oil price assumptions reflecting market dynamics and updated production and cost profiles, including in particular the impact of a weaker USD. The net reversal is made up from a reversal of $49.4 million at Kraken offset by charges of $19.6 million for GKA and Scolty/Crathes, $23.4 million for Golden Eagle and $5.9 million for Alba.
The reversal on Kraken reflects, in particular, the impact of the reduced discount rate on this long life asset, whereas the impairment charges for GKA, Golden Eagle and Alba primarily reflect the impact of short-term price reductions and exchange rate movements on these short life assets.
The 1H 2024 net impairment charge of $21.0 million relates to producing assets in the UK North Sea. These were primarily driven by changes in production and cost profiles, including higher decommissioning cost estimates, and an extension of the UK Energy Profits Levy to 31 March 2029 offset partially by an increase in EnQuest's future oil price assumptions and a lower discount rate of 10.5% at 30 June 2024.
Sensitivity analyses
Management tested the impact of a change in cash flows in FVLCD impairment testing arising from a 10.0% reduction in price assumptions.
Price reductions of this magnitude in isolation could indicatively lead to a further reduction in the carrying amount of EnQuest's oil and gas properties by approximately $198.3 million, which is approximately 9% of the net book value of property, plant and equipment as at 30 June 2025.
The oil price sensitivity analysis above does not, however, represent management's best estimate of any impairments that might be recognised as it does not incorporate consequential changes that may arise, such as reduction in costs and to business plans, phasing of development, levels of reserves and resources, and production volumes. As the extent of a price reduction increases, the more likely it is that costs would decrease across the industry. The oil price sensitivity analysis therefore does not reflect a linear relationship between price and value that can be extrapolated.
Management also tested the impact of a 1.0% change in the discount rate of 9.5% used for FVLCD impairment testing of oil and gas properties which is considered a reasonably possible change given the prevailing macroeconomic conditions. If the discount rate was 1.0% higher across all tests performed, the net impairment recognised in the first half of 2025 would have been approximately $48.6 million higher. If the discount rate was 1.0% lower, the net impairment reversal recognised would have been approximately $53.1 million higher.
8. Loans and borrowings
30 June 2025 $'000
31 December 2024 $'000
Loans
60,425
33,972
Bonds
648,399
630,885
708,824
664,857
The Group's borrowings are carried at amortised cost as follows:
30 June 2025
31 December 2024
Principal $'000
Fees $'000
Total $'000
Principal $'000
Fees $'000
Total $'000
SVT working capital facility
37,027
-
37,027
33,972
-
33,972
Vendor loan facility(i)
22,519
-
22,519
-
-
-
USD High yield bond 11.625%
465,000
(8,572)
456,428
465,000
(10,661)
454,339
GBP Retail bond 9.00%
182,805
-
182,805
167,101
-
167,101
Accrued interest(ii)
10,045
-
10,045
9,445
-
9,445
Total borrowings
717,396
(8,572)
708,824
675,518
(10,661)
664,857
Due within one year
69,591
43,417
Due after more than one year
639,233
621,440
Total borrowings
708,824
664,857
(i) In August 2024, the Group entered into a deferred payment facility agreement with a third-party vendor providing capacity for refinancing the payment of existing invoices up to an amount of £23.7 million, with interest payable monthly at a rate of 9.50% per annum
(ii) Accrued interest includes vendor loan facility interest accruals of $0.9 million (31 December 2024: nil) and bond interest accruals of $9.2 million (31 December 2024: $9.4 million)
There was no loan drawdown under the Group's RBL at 30 June 2025 (31 December 2024: $nil). At 30 June 2025, $239.9 million remained available for drawdown under the facility, while $70.7 million for letters of credit were utilised.
9. Other financial assets and financial liabilities
(a) Summary as at 30 June 2025
30 June 2025
31 December 2024
Assets $'000
Liabilities $'000
Assets $'000
Liabilities $'000
Fair value through profit or loss:
Derivative commodity contracts
28,652
5,860
69
10,497
Forward foreign currency contracts
13,670
-
-
2,354
Derivative UKA contracts
-
281
-
8,729
Total current
42,322
6,141
69
21,580
Fair value through profit or loss:
Quoted equity shares
6
-
6
-
Amortised Cost:
Other receivables (Vendor financing facility)
43,443
-
38,453
-
Total non-current
43,449
-
38,459
-
Total other financial assets and liabilities
85,771
6,141
38,528
21,580
(b) Income statement impact
The income/(expense) recognised for derivatives are as follows:
Period ended 30 June 2025
Revenue and other operating income
Cost of sales
Realised $'000
Unrealised $'000
Realised $'000
Unrealised $'000
Commodity options
(1,020)
1,967
-
-
Commodity swaps
2,251
30,994
-
-
Commodity futures
(212)
246
-
-
Foreign exchange contracts
-
-
11,239
16,024
UKA contracts
-
-
(1,674)
8,448
1,019
33,207
9,565
24,472
Period ended 30 June 2024
Revenue and other operating income
Cost of sales
Realised $'000
Unrealised $'000
Realised $'000
Unrealised $'000
Commodity options
(9,285)
1,312
-
-
Commodity swaps
858
(3,224)
-
-
Commodity futures
(2,237)
-
-
-
Foreign exchange contracts
-
-
583
859
UKA contracts
-
-
(5,999)
6,995
(10,664)
(1,912)
(5,416)
7,854
(c) Fair value measurement
30 June 2025
Notes
Carrying value $'000
Total $'000
Quoted prices in active markets (Level 1) $'000
Significant observable inputs (Level 2) $'000
Significant unobservable inputs (Level 3) $'000
Financial assets measured at fair value:
Derivative financial assets measured at FVPL
Commodity contracts
28,652
28,652
-
28,652
-
Forward foreign currency contracts
13,670
13,670
-
13,670
-
Other financial assets measured at FVPL
-
Quoted equity shares
6
6
6
-
-
Total financial assets measured at fair value
42,328
42,328
6
42,322
-
Financial assets measured at amortised cost:
Vendor financing facility
43,443
43,443
-
43,443
-
Total financial assets measured at amortised cost (i)
43,443
43,443
-
43,443
-
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Commodity derivative contracts
5,860
5,860
-
5,860
-
Forward UKA contracts
281
281
-
281
-
Other financial liabilities measured at FVPL
Contingent consideration
457,780
457,780
-
-
457,780
Total liabilities measured at fair value
463,921
463,921
-
6,141
457,780
Liabilities measured at amortised cost:
Interest-bearing loans and borrowings (i)
8
60,425
60,425
-
60,425
-
GBP Retail bond 9.00% (ii)
8
185,078
184,048
184,048
-
-
USD High yield bond 11.625% (ii)
8
463,321
475,216
475,216
-
-
Total liabilities measured at amortised cost(iii)
708,824
719,689
659,264
60,425
-
(i) Amortised cost is a reasonable approximation of the fair value. Carrying value includes accrued interest (ii) Carrying value includes accrued interest (iii) Excludes related fees
31 December 2024
Notes
Carrying value $'000
Total $'000
Quoted prices in active markets (Level 1) $'000
Significant observable inputs (Level 2) $'000
Significant unobservable inputs (Level 3) $'000
Financial assets measured at fair value:
Derivative financial assets measured at FVPL
Gas commodity contracts
69
69
-
69
-
Other financial assets measured at FVPL
Quoted equity shares
6
6
6
-
-
Total financial assets measured at fair value
75
75
6
69
-
Financial assets measured at amortised cost:
Vendor financing facility
38,453
38,453
-
38,453
-
Total financial assets measured at amortised cost (i)
38,453
38,453
-
38,453
-
Liabilities measured at fair value:
Derivative financial liabilities measured at FVPL
Commodity derivative contracts
10,497
10,497
-
10,497
-
Forward foreign currency contracts
2,354
2,354
-
2,354
-
Forward UKA contracts
8,729
8,729
-
8,729
-
Other financial liabilities measured at FVPL
Contingent consideration
473,294
473,294
-
-
473,294
Total liabilities measured at fair value
494,874
494,874
-
21,580
473,294
Liabilities measured at amortised cost:
Interest-bearing loans and borrowings(i)
8
33,972
33,972
-
33,972
-
GBP Retail bond 9.00%(ii)
8
169,371
161,461
161,461
-
-
USD High yield bond 7.00%(ii)
8
461,514
466,102
466,102
-
-
Total liabilities measured at amortised cost (iii)
664,857
661,535
627,563
33,972
-
(i) Amortised cost is a reasonable approximation of the fair value
(ii) Carrying value includes accrued interest
(iii) Excludes related fees
Fair value hierarchy
All financial instruments for which fair value is recognised or disclosed are categorised within the fair value hierarchy, based on the lowest level input that is significant to the fair value measurement as follows:
Level 1: Quoted (unadjusted) market prices in active markets for identical assets or liabilities;
Level 2: Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly (i.e. prices) or indirectly (i.e. derived from prices) observable;
Level 3: Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable.
Derivative financial instruments are valued by counterparties, with the valuations reviewed internally and corroborated with readily available market data (Level 2). Contingent consideration is measured at FVPL using the Level 3 valuation processes details of which and a reconciliation of movements are disclosed in note 10. There have been no transfers between Level 1, Level 2 and Level 3 during the period (2024: no transfers).
For the financial assets and liabilities measured at amortised costs but for which fair value disclosures are required, the fair value of the bonds classified as Level 1 was derived from quoted prices for each financial instrument. Interest-bearing loans and borrowings and the vendor financing facility were calculated at amortised cost using the effective interest method to capture the present value (Level 2). A reconciliation of movements is disclosed in note 13.
10. Contingent consideration
Magnus 75% $'000
Magnus decommissioning-linked liability $'000
Total $'000
At 31 December 2024
451,333
21,961
473,294
Change in fair value
(43,903)
2,223
(41,680)
Unwinding of discount(i)
25,500
1,241
26,741
Utilisation
-
(575)
(575)
At 30 June 2025
432,930
24,850
457,780
Classified as:
Current
10,554
997
11,551
Non-current
422,376
23,853
446,229
432,930
24,850
457,780
(i) In previous periods, the unwinding of discount has been recorded within finance costs in the income statement, with remaining fair value movements recorded within other income or expense. Following a review of this presentation for the year ended 31 December 2024 and comparing this to market practice, it was concluded that it would be more appropriate for the impact from both the unwind of discount and other changes in fair value to be combined within other income/expense, with comparative information restated. This restatement results in a $28.7 million charge for the six months ended 30 June 2024 being reclassified from finance costs to other income/expense, with no impact on net income or closing retained earnings for that period.
75% Magnus acquisition contingent consideration
The contingent consideration ('profit share arrangement') was fair valued at 30 June 2025, which resulted in a decrease in fair value (excluding the impact of unwind of discount) of $43.9 million. This decrease reflects lower near-term oil prices and a weaker USD combined with changes to production and cost profiles (30 June 2024: increase of $13.3 million reflecting a change in the Group's oil price assumptions partially offset by production profile changes). The overall fair value accounting effect including unwinding of discount, totalling a credit of $18.4 million (30 June 2024: $40.9 million charge), on the contingent consideration were recognised in the Group income statement. The profit share payment is disclosed separately under investing activities within the statement of cash flows (30 June 2025: $nil; 30 June 2024: $48.1 million). At 30 June 2025, the contingent consideration was $432.9 million (31 December 2024: $451.3 million). At 30 June 2025, the contingent profit-sharing arrangement cap of $1 billion is forecast to be met in the present value calculations (31 December 2024: cap was forecast to be met).
Management has considered alternative scenarios to assess the valuation of the contingent consideration including, but not limited to, the key accounting estimate relating to discount rate, the oil price and the interrelationship with production and the profit-share arrangement. A 1.0% reduction in the discount rate applied, which is considered a reasonably possible change given the prevailing macroeconomic conditions, would increase contingent consideration by $20.5 million. A 1.0% increase would decrease contingent consideration by $19.1 million. At 30 June 2025, the contingent profit-sharing cap of $1.0 billion is forecast to be met in the present value calculations (31 December 2024: cap was forecast to be met), therefore sensitivity analysis has only been undertaken on a reduction in the price assumptions of 10%, which is considered to be a reasonably possible change. This results in a reduction of $66.7 million to the contingent consideration (31 December 2024: reduction of $51.1 million).
Magnus decommissioning-linked contingent consideration
As part of the Magnus and associated interests acquisition, bp retained the decommissioning liability in respect of the existing wells and infrastructure and EnQuest agreed to pay additional consideration in relation to the management of the physical decommissioning costs of Magnus. At 30 June 2025, the amount due to bp, calculated on an after-tax basis by reference to 30% of bp's decommissioning costs on Magnus, was $24.9 million (31 December 2024: $22.0 million). Any reasonably possible change in assumptions would not have a material impact on the provision.
11. Provisions
Decommissioning provision $'000
Thistle decommissioning provision $'000
Other provisions $'000
Total $'000
At 31 December 2024
741,565
18,348
6,193
766,106
Additions
2,482
-
-
2,482
Changes in estimates
46,552
1,399
(4,690)
43,261
Unwinding of discount
16,565
413
-
16,978
Utilisation
(18,084)
(4,072)
(3)
(22,159)
Foreign exchange
-
-
18
18
At 30 June 2025
789,080
16,088
1,518
806,686
Classified as:
Current
47,069
5,579
1,119
53,767
Non-current
742,011
10,509
399
752,919
789,080
16,088
1,518
806,686
Decommissioning provision
The Group's total provision represents the present value of decommissioning costs which are expected to be incurred up to 2050, assuming no further development of the Group's assets. The Group's decommissioning provision has increased by $47.5 million in the period. This primarily reflects higher cost estimates of $46.6 million, predominantly due to a weaker US Dollar, offset partly by the ongoing decommissioning programmes utilisation of $18.1 million. At 30 June 2025, an estimated $267.5 million is expected to be utilised between one and five years (31 December 2024: $240.1 million), $288.5 million within six to ten years (31 December 2024: $280.0 million), and the remainder in later periods.
The Group enters into surety bonds principally to provide security for its decommissioning obligations. At 30 June 2025, the Group held surety bonds totalling $263.2 million (31 December 2024: $277.0 million).
Changes in assumptions, including cost reduction factors, in relation to the Group's provisions could result in a material change in their carrying amounts within the next financial year. A 1.0% decrease in the nominal discount rate applied, which is considered a reasonably possible change given the prevailing macroeconomic environment, could increase the Group's provision balances by approximately $61.1 million. The pre-tax impact on the Group income statement would be a charge of approximately $59.9 million, reflecting the change in estimates for assets which have already ceased production.
Thistle decommissioning provision
At 30 June 2025, the amount due to bp by reference to 7.5% of bp's decommissioning costs on Thistle and Deveron was $16.1 million (31 December 2024: $18.3 million), with the reduction mainly reflecting the utilisation in the period offset partly from an increase in the fair value due to a weaker US Dollar. Unwinding of discount of $0.4 million is included within finance costs for the period ended 30 June 2025 (30 June 2024: $0.4 million).
12. Commitments and contingencies
Capital commitments
At 30 June 2025, the Group had commitments for future capital expenditure amounting to $75.3 million (31 December 2024: $13.3 million). The increase relates to the development of the non-associated gas resources in the PM8/Seligi PSC contract area under the Seligi 1b gas agreement, first gas from which has been accelerated to Q1 2026. The key remaining component of this relates to the new stabilisation facility at Sullom Voe Terminal. Where the commitment relates to a joint venture, the amount represents the Group's net share of the commitment. Where the Group is not the operator of the joint venture then the amounts are based on the Group's net share of committed future work programmes.
Other commitments
In the normal course of business, the Group will obtain surety bonds, letters of credit and guarantees. At 30 June 2025, the Group held surety bonds totalling $263.2 million (31 December 2024: $277.0 million) to provide security for its decommissioning obligations.
Contingencies
The Group becomes involved from time to time in various claims and lawsuits arising in the ordinary course of its business. Outside of those already provided the Group is not, nor has been during the past 12 months, involved in any governmental, legal or arbitration proceedings which, either individually or in the aggregate, have had, or are expected to have, a material adverse effect on the Group's financial position or profitability, nor, so far as the Group is aware, are any such proceedings pending or threatened.
13. Cash flow information
Cash generated from operations
Notes
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Profit/(loss) before tax
65,577
111,278
Depreciation
7
2,812
3,091
Depletion
7
124,002
136,732
Net impairment (reversal)/charge to oil and gas assets
7
(532)
20,995
Net disposal/(write back) of inventory
530
(5,240)
Other non-cash income
-
(1,645)
Share-based payment charge
118
895
Change in Magnus related contingent consideration
10
(14,939)
42,454
Change in provisions
29,740
18,628
Unrealised (gain)/loss on commodity financial instruments
(33,207)
1,912
Unrealised gain on other financial instruments
(24,472)
(7,854)
Unrealised exchange loss/(gain)
24,753
(8,659)
Net finance expense
56,174
54,949
Operating cash flow before working capital changes
230,556
367,536
(Increase)/decrease in trade and other receivables
(16,087)
5,415
(Increase) in inventories
(7,534)
(1,536)
Increase/(decrease) in trade and other payables
8,289
(2,543)
Cash generated from operations
215,224
368,872
Changes in liabilities arising from financing activities
Loans and borrowings $'000
Bonds $'000
Lease liabilities $'000
Total $'000
At 31 December 2024
(33,972)
(630,885)
(335,255)
(1,000,112)
Cash movements:
Repayments of loans and borrowings
6,451
-
-
6,451
Proceeds from loans and borrowings
(27,420)
-
-
(27,420)
Payment of lease liabilities
-
-
35,441
35,441
Cash interest paid in period(i)
667
34,757
-
35,424
Non-cash movements:
Additions
-
-
(28,291)
(28,291)
Interest/finance charge payable
(1,546)
(34,587)
(11,388)
(47,521)
Fee amortisation
(703)
(2,332)
-
(3,035)
Foreign exchange and other non-cash movements
(3,902)
(15,352)
(7,009)
(26,263)
At 30 June 2025
(60,425)
(648,399)
(346,502)
(1,055,326)
(i) The cashflow statement includes interest on decommissioning bonds and Letters of Credit
Reconciliation of carrying value
Loans and borrowings $'000
Bonds $'000
Lease liabilities $'000
Total $'000
Principal
59,546
647,805
346,502
1,053,853
Unamortised fees
-
(8,572)
-
(8,572)
Accrued interest
879
9,166
-
10,045
At 30 June 2025
60,425
648,399
346,502
1,055,326
14. Distributions paid and proposed
In April 2025, the Board proposed a final ordinary dividend of 0.616 pence per share (equivalent to c.$15 million). This was approved by shareholders at the Annual General Meeting on 27 May 2025 and paid on 6 June 2025 to shareholders on the register at 2 May 2025. There is no interim dividend proposed.
15. Subsequent events
In January 2025, EnQuest announced that it had signed a Sale and Purchase Agreement to acquire Harbour Energy's business in Vietnam, which includes the 53.125% equity interest in the Chim Sáo and Dua production fields. These fields are governed by the Block 12W Production Sharing Contract, which runs to November 2030 with an opportunity to extend. The transaction completed on 9 July 2025, with consideration paid by EnQuest on completion of $22.1 million, being the headline value of the transaction of $85.1 million, net of interim period cash flows from 1 January 2024 and a deposit paid in 1H 2025 of $3.6 million. As at 1 January 2025, net 2P reserves and 2C resources across the fields totalled 7.5 million boe and 4.9 million boe, respectively.
In July 2025, EnQuest announced that it had been awarded a Production Sharing Agreement ('PSA') for Block C located offshore Brunei Darussalam which hosts the condensate rich gas discovered fields of Merpati, Meragi and Juragan. EnQuest will initially be the sole operator of the PSA with the intention to subsequently, subject to contract, form a 50/50 joint venture company ('JVC') with Brunei Energy Exploration Sdn Bhd. Once established, the JVC will assume the role of operator for Block C and focus on finalising the Merpati Field Development Plan with a view to achieving a Final Investment Decision within two years. It is expected that the capital project will commence in 2027, with first gas from the field to be online in 2029.
In August 2025, EnQuest announced that, together with its joint venture partners and the Government of Indonesia, it has signed Production Sharing Contracts ('PSCs') for the Gaea and Gaea II exploration blocks, located in Papua Barat, Indonesia. Under the PSC terms, EnQuest has a 40% participating interest in the blocks and is the PSC operator.
Statement of Directors' Responsibilities
We confirm that to the best of our knowledge:
a) the condensed set of financial statements has been prepared in accordance with the UK-adopted IAS 34 'Interim Financial Reporting';
b) the interim management report includes a fair review of the information required by DTR 4.2.7R (indication of important events and their impact during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and
c) the interim management report includes a fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein).
A list of current Directors is maintained on the EnQuest PLC website which can be found at www.enquest.com.
By the order of the Board
Jonathan Copus
Chief Financial Officer
23 September 2025
Independent review report to EnQuest PLC
Conclusion
We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2025 which comprises the Group Income Statement, the Group Balance Sheet, the Group Statement of Changes in Equity, the Group Statement of Cash Flows and related notes 1 to 15.
Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2025 is not prepared, in all material respects, in accordance with United Kingdom adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
Basis for Conclusion
We conducted our review in accordance with International Standard on Review Engagements (UK) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Financial Reporting Council for use in the United Kingdom (ISRE (UK) 2410). A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
As disclosed in note 2, the annual financial statements of the group are prepared in accordance with United Kingdom adopted international accounting standards. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with United Kingdom adopted International Accounting Standard 34, "Interim Financial Reporting".
Conclusion Relating to Going Concern
Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for Conclusion section of this report, nothing has come to our attention to suggest that the directors have inappropriately adopted the going concern basis of accounting or that the directors have identified material uncertainties relating to going concern that are not appropriately disclosed.
This conclusion is based on the review procedures performed in accordance with ISRE (UK) 2410; however future events or conditions may cause the entity to cease to continue as a going concern.
Responsibilities of the directors
The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
In preparing the half-yearly financial report, the directors are responsible for assessing the group's ability to continue as a going concern, disclosing as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the company or to cease operations, or have no realistic alternative but to do so.
Auditor's Responsibilities for the review of the financial information
In reviewing the half-yearly financial report, we are responsible for expressing to the company a conclusion on the condensed set of financial statement in the half-yearly financial report. Our conclusion, including our Conclusion Relating to Going Concern, are based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report.
Use of our report
This report is made solely to the company in accordance with ISRE (UK) 2410. Our work has been undertaken so that we might state to the company those matters we are required to state to it in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.
Deloitte LLP
Statutory Auditor
London, United Kingdom
23 September 2025
Glossary - Non-GAAP measures
The Group uses Alternative Performance Measures ('APMs') when assessing and discussing the Group's financial performance, balance sheet and cash flows that are not defined or specified under IFRS but consistent with accounting policies applied in the financial statements. The Group uses these APMs, which are not considered to be a substitute for, or superior to, IFRS measures, to provide stakeholders with additional useful information, to aid the understanding of the Group's financial performance, balance sheet and cash flows by adjusting for certain items, as set out on page 189 of the Group's 2024 annual consolidated financial statements, which impact upon IFRS measures or, by defining new measures.
The use of the APMs are explained in note 2 of the Group's annual consolidated financial statements, published in April 2025, on page 142.
Adjusted net (loss)/profit attributable to EnQuest PLC shareholders
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Net (loss)/profit (A)
(173,502)
30,348
Adjustments - remeasurements and exceptional items:
Unrealised gains on derivative contracts (note 9b)
57,679
5,942
Net impairment (charge)/reversal to oil and gas assets (note 7)
532
(20,995)
Change in Magnus contingent consideration (note 10)
14,939
(42,454)
Change in other provisions
4,691
-
Insurance (charge)/income on Kraken shutdown and PM8/Seligi riser incident
(53)
1,645
Pre-tax remeasurements and exceptional items (B)
77,788
(55,862)
Tax on above remeasurements and exceptional items
(84,332)
2,029
UK Energy Profits Levy extension to 2030
(123,875)
-
Total tax on remeasurements and exceptional items (C)
(208,207)
2,029
Post-tax remeasurements and exceptional items (D = B + C)
(130,419)
(53,833)
Adjusted net (loss)/profit attributable to EnQuest PLC shareholders (A - D)
(43,083)
84,181
Adjusted EBITDA is a measure of profitability. It provides a metric to show earnings before the influence of accounting (e.g. depletion and depreciation) and financial deductions (e.g. borrowing interest) and other adjustments set out in the table below. For the Group, this is a useful metric as a measure to evaluate the Group's underlying operating performance and is a component of a covenant measure under the Group's RBL facility. It is commonly used by stakeholders as a comparable metric of core profitability and can be used as an indicator of cash flows available to pay down debt. Due to the adjustment made to reach adjusted EBITDA, the Group notes the metric should not be used in isolation. The nearest equivalent measure on an IFRS basis is profit/(loss) from operations before tax and finance income/(costs).
Adjusted EBITDA
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Reported profit/(loss) from operations before tax and finance income/(costs)
138,728
179,884
Adjustments:
Unrealised gains on derivative contracts
(57,679)
(5,941)
Net impairment charge/(reversal) to oil and gas assets
(532)
20,995
Change in Magnus contingent consideration
(14,939)
42,454
Insurance income on Kraken and PM8/Seligi riser incident
53
(1,645)
Depletion and depreciation (note 7)
126,814
139,823
Inventory revaluation
530
(5,240)
Change in decommissioning and other provisions
12,761
4,928
Net foreign exchange loss/(gain)
28,874
(7,753)
Adjusted EBITDA (E)
234,610
367,504
Total cash and available facilities is a measure of the Group's liquidity at the end of the reporting period. The Group believes this is a useful metric as it is an important reference point for the Group's going concern assessment, see page 11.
Total cash and available facilities
Period ended 30 June 2025 $'000
Year ended 31 December 2024 $'000
Available cash
260,020
226,317
Restricted cash
70,710
53,922
Total cash and cash equivalents (F)
330,730
280,239
Available undrawn facilities (G)(i)
247,057
194,256
Total cash and available facilities (F + G)
577,787
474,495
(i)Includes amounts available under the RBL: $239.9 million (31 December 2024: $176.4 million), vendor loan facility providing capacity for refinancing the payment of existing invoices up to an amount of £23.7 million: $7.2 million available (31 December 2024: $17.9 million)
Net debt is a liquidity measure that shows how much debt a company has on its balance sheet compared to its cash and cash equivalents. It is an important reference point for the Group's going concern assessment, see page 11. The Group's definition of net debt, referred to as EnQuest net debt, excludes unamortised fees, accrued interest and the Group's finance lease liabilities as the Group's focus is the management of cash borrowings and a lease is viewed as deferred capital investment.
EnQuest net debt
Period ended 30 June 2025 $'000
Year ended 31 December 2024 $'000
Loans and borrowings (note 8):
SVT working capital facility
37,027
33,972
Vendor loan facility
22,519
-
Bonds (note 8):
USD High yield bond
456,428
454,339
GBP Retail bond
182,805
167,101
Accrued interest
10,045
9,445
Loans and borrowings (H)
708,824
664,857
Non-cash accounting adjustments (note 8):
Unamortised fees on bonds
8,572
10,661
Accrued interest
(10,045)
(9,445)
Non-cash accounting adjustments (I)
(1,473)
1,216
Debt (H + I) (J)
707,351
666,073
Less: Cash and cash equivalents (F)
330,730
280,239
EnQuest net debt (J - F) (K)
376,621
385,834
The EnQuest net debt/adjusted EBITDA metric is a ratio that provides management and users of the Group's consolidated financial statements with an indication of the Group's ability to settle its debt. This is a helpful metric to monitor the Group's progress against its strategic objective of maintaining balance sheet discipline.
EnQuest net debt/adjusted EBITDA
Period ended 30 June 2025 $'000
Year ended 31 December 2024 $'000
EnQuest net debt (K)
376,621
385,834
Adjusted EBITDA (last 12 months) (E)
539,691
672,585
EnQuest net debt/adjusted EBITDA (K/E)
0.7
0.6
Cash capital expenditure (nearest equivalent measure on an IFRS basis is purchase of property, plant and equipment) monitors investing activities on a cash basis, while cash decommissioning expense monitors the Group's cash spend on decommissioning activities. The Group provides guidance to the financial markets for both these metrics given the materiality of the work programmes.
Cash capital expenditure and decommissioning expense
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Reported net cash flows (used in)/from investing activities
(83,776)
(30,147)
Adjustments:
Payment of Magnus contingent consideration - Profit share
-
48,118
Proceeds from vendor financing facility receipt
-
(107,518)
Proceeds from Bressay farm-down
-
(1,263)
Acquisition deposit
3,550
-
Interest received
(2,992)
(4,181)
Cash capital expenditure
(83,218)
(94,991)
Decommissioning expenditure
(31,387)
(31,516)
Cash capital expenditure and decommissioning expense
(114,605)
(126,507)
Adjusted free cash flow ('FCF') represents the cash a company generates, after accounting for cash outflows to support operations and to maintain its capital assets. It excludes movements in loans and borrowings, net proceeds from share issues, the impact of acquisitions and disposals and shareholder distributions. Currently this metric is useful to management and users to assess the Group's ability to allocate capital across a range of activities - including investment, shareholder distributions, transactions and debt management.
Adjusted free cash flow
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Net cash flows from/(used in) operating activities
191,948
323,418
Adjustments:
Purchase of property, plant and equipment
(81,252)
(93,629)
Purchase of oil and gas and other intangible assets
(1,966)
(1,362)
Payment of Magnus contingent consideration
-
(48,118)
Interest received
2,992
4,181
Payment of obligations under finance lease
(35,441)
(85,020)
Interest paid
(43,554)
(43,975)
Adjusted free cash flow
32,727
55,495
Average realised price is a measure of the revenue earned per barrel sold. The Group believes this is a useful metric for comparing performance to the market and to give the user, both internally and externally, the ability to understand the drivers impacting the Group's revenue.
Revenue from sales
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Revenue from crude oil sales (note 4) (L)
403,965
523,065
Revenue from gas and condensate sales (note 4)
108,180
73,449
Realised gains/(losses) on oil derivative contracts (note 4) (M)
1,019
(10,664)
Barrels equivalent sales
Period ended 30 June 2025 kboe
Period ended 30 June 2024 kboe
Sales of crude oil (N)
5,702
6,145
Sales of gas and condensate(i)
1,252
1,235
Total sales
6,954
7,380
(i) Includes volumes related to onward sale of third-party gas purchases not required for injection activities at Magnus
Average realised prices
Period ended 30 June 2025 $/Boe
Period ended 30 June 2024 $/Boe
Average realised oil price, excluding hedging (L/N)
70.8
85.1
Average realised oil price, including hedging ((L + M)/N)
71.0
83.4
Operating costs ('opex') is a measure of the Group's cost management performance (reconciled to reported cost of sales, the nearest equivalent measure on an IFRS basis). Opex is a key measure to monitor the Group's alignment to its strategic pillars of financial discipline and value enhancement and is required in order to calculate opex per barrel (see below).
Operating costs
Period ended 30 June 2025 $'000
Period ended 30 June 2024 $'000
Total cost of sales
388,935
352,310
Adjustments:
Unrealised (losses)/gains on derivative contracts related to operating costs
24,472
7,854
Depletion of oil and gas assets
(124,002)
(136,732)
Credit/(charge) relating to the Group's lifting position and inventory
1,488
22,807
Other cost of operations(i)
(108,138)
(63,222)
Operating costs
182,755
183,017
Less realised gain/(loss) on derivative contracts (P)
9,565
(5,416)
Operating costs directly attributable to production
192,320
177,601
Comprising of:
Production costs (Q)
156,350
143,618
Tariff and transportation expenses (R)
35,970
33,983
Operating costs directly attributable to production
192,320
177,601
(i) Includes $96.4 million (2024: $52.4 million) of purchases and associated costs of third-party gas not required for injection activities at Magnus which is sold on
Barrels equivalent produced
Period ended 30 June 2025 kboe
Period ended 30 June 2024 kboe
Total produced (working interest) (S)(i)
6,925
7,784
(i) Production figure includes 498 kboe associated with Seligi gas (2024: 294 kboe)
Unit opex is the operating expenditure per barrel of oil equivalent produced. This metric is useful as it is an industry standard metric allowing comparability between oil and gas companies. Unit opex including hedging includes the effect of realised gains and losses on derivatives related to foreign currency and emissions allowances. This is a useful measure for investors because it demonstrates how the Group manages its risk to market price movements.
Unit opex
Period ended 30 June 2025 $/Boe
Period ended 30 June 2024 $/Boe
Production costs (Q/S)
22.6
18.4
Tariff and transportation expenses (R/S)
5.2
4.4
Total unit opex ((Q + R)/S)
27.8
22.8
Realised (gain) / loss on derivative contracts (P/S)
(1.4)
0.7
Total unit opex including hedging ((P + Q+ R)/S)
26.4
23.5
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