Half-year Results

EnQuest PLC

Results for the six months ended 30 June 2026

3 September 2026

Unless otherwise stated, all figures are in US Dollars.

Comparative figures for the Income statement relate to the period ended 30 June 2025 and the Balance sheet as at 31 December 2025. Alternative performance measures are reconciled within the 'Glossary - Non-GAAP measures' at the end of the Financial Statements.

EnQuest Chief Executive, Amjad Bseisu, said:

"The first half of 2026 has marked a seminal period in EnQuest's evolution. We have taken significant steps to grow and strengthen the business, building a portfolio with greater diversity, longevity and resilience. Our highly tangible reserves and resources, differentiated operating expertise, and increasingly diversified geographic footprint provide a strong platform from which to create long-term value through commodity cycles.

"In announcing our transformational acquisitions in Malaysia, and subsequently satisfying all conditions precedent to the transaction, we have laid the foundations for the next chapter of EnQuest's growth story. As we work towards the transfer of operatorship, ahead of completion on 31 December, we are preparing to become a business of a fundamentally different scale, with Group production of more than 100,000 Boepd through to the end of the decade, total 2P reserves and 2C resources of c.1 billion barrels of oil equivalent, structurally reduced costs, extended portfolio longevity and enhanced cash flows. Importantly, it further strengthens our strategic partnership with PETRONAS Carigali and positions EnQuest at the centre of one of the most attractive upstream investment regions globally, broadening our opportunity set for future value-accretive growth.

"We also remain committed to the UK North Sea and continue to see significant opportunities to create value through responsible stewardship, operational excellence and disciplined investment. With the fiscal solution already being available to government in the form of the Oil and Gas Revenue Levy (formerly named the Oil and Gas Price Mechanism), we are hopeful that the change in political leadership will be accompanied by a renewed focus on competitiveness, investment and energy security. Restoring confidence and attracting capital to the basin requires a stable and durable fiscal framework that supports long-term investment, protects highly skilled jobs and recognises the critical role domestic energy production continues to play in meeting the UK's energy needs.

"Our activities are underpinned by our continued focus on financial strength and strategic flexibility. The refinancing of our reserve-based lending ('RBL') facility and bonds, and the settlement of the Magnus contingent consideration have enhanced our liquidity, simplified our balance sheet and increased our capacity to pursue strategic opportunities. Together with disciplined capital allocation and our continued focus on operational excellence, these actions have created a platform from which we can confidently execute the next phase of our growth strategy.

"EnQuest enters the second half of 2026 from a position of strength and, looking ahead, 2027 will mark the beginning of a new era for the Group. With a larger and more diverse production base, stronger cash generation and an expanded inventory of organic and inorganic growth opportunities, we are creating an EnQuest that is fundamentally different in scale, but which remains true to the disciplined, value-focused approach that has defined our success. As we complete the Malaysia transaction and begin integrating these world-class assets, we believe the years ahead have the potential to be the most exciting and value-creating in the Company's history."

H1 2026 performance

In the six months to 30 June 2026, against a backdrop of elevated but volatile crude prices, EnQuest delivered production growth, strong operational cash flow and announced a series of significant capital structure and transactional steps that will fundamentally reshape the Group.

Delivering a growth-led platform of scale:

· In June, EnQuest announced it was acquiring participating interests in four Malaysian Production Sharing Contracts ('PSCs'). All conditions precedent were met in August, and the transaction is on track to complete on 31 December 2026, with an effective date of 1 January 2027. Based on 2025 figures for the Enlarged Group:

o  Production to total c.100,000 Boepd (134% increase), underpinned by c.300 MMboe of 2P reserves (c.85% increase), with low unit production costs of $16/Boe (c.35% reduction) and minimal 2P capex.

o  EnQuest will operate c.96% of the enlarged 2P portfolio, which remains highly tangible (77% of 2P reserves are in the 1P or "Proven" category).

o  Balance sheet discipline is maintained - assuming Completion on 31 December 2025, the Enlarged Group's net debt / adjusted LTM EBITDA leverage would have been 1.1x.

· Material growth opportunities in both Asia and the UK North Sea.

o  Total 2C resources of c.660 MMboe for the Enlarged Group (up 46%) plus c.65-100 MMboe of recovery factor upside.

o  Group-wide investment review underway, to accelerate 2C to 2P conversion and maximise value-led production growth.

o  EnQuest remains very active in both the UK North Sea and South East Asia, as the Group looks to execute further value-enhancing acquisitions.

Base operations:

· First half production rose 9% year-on-year, averaging 41,544 Boepd (H1 2025: 38,257 Boepd).

o  New fields in South East Asia performed strongly: Block 12W oil (Vietnam), Seligi 1b gas (Malaysia). This was partially offset by a previously communicated third-party infrastructure outage that curtailed Magnus by c.4,100 Boepd.

o  Magnus downtime deferred one cargo sale out of H1 2026, with an equivalent cash impact of c.$60 million, and the effect of adding c.$3/Boe to the Group's unit opex for the period.

· Despite Magnus disruption, cash generated by operations totalled $281.4 million (a 31% year-on-year increase) and underlying adjusted free cash flow totalled $71.3 million (a 118% year-on-year increase).

o  By deploying EnQuest's proven late-life asset management expertise, payback on the Vietnam acquisition has been achieved in less than 12 months.

o  With non-cash unrealised hedging impacting the Income Statement position, EnQuest reported a $39.9 million post-tax loss (H1 2025: $173.5 million loss) on reported revenue of $529.9 million (2025: $549.1 million). On an adjusted basis, the loss reduces to $9.0 million.

· In addition to the Malaysian transaction detailed above, in the period EnQuest also:

o  Settled the Magnus Contingent Consideration liability through a $60.0 million cash payment, which eliminated a $432.9 million balance sheet liability (last reported on 30 June 2025) and drove a c.38% expansion in RBL capacity.

o  Refinanced its High yield bonds, reducing borrowing costs by 175 bp and further simplifying the capital structure. Refinancing costs, inclusive of early redemption costs, totalled c.$35.0 million.

· Inclusive of the above steps, and in addition to June payments of a $27.7 million Malaysia acquisition deposit and the $20.2 million dividend to shareholders, EnQuest net debt at 30 June 2026 totalled $517.0 million (31 Dec 2025: $433.9 million). The Group net debt / adjusted LTM EBITDA ratio widened slightly to 1.0x (31 Dec 2025: 0.9x).

· Cash and available facilities at 30 June 2026 rose to $758.6 million (end 2025: $678.6 million).

Guidance:

· EnQuest remains on track to deliver production within the guidance range set at the start of the year. Following the Magnus operational interruption, the Group is tightening production guidance to 41 to 43 Kboed.

· Full year asset expenditure is expected to remain unchanged from the Group's original guidance of $670 million (operating expenditure c.$450 million, cash capital c.$160 million and abandonment expenditure c.$60 million).

· For the period September to December 2026, the Group has c.2.2 MMbbls of production hedged. Of these 0.6 MMbbls are via collars with an average floor price of $50.2/bbl and an average ceiling price of c.$89.5/bbl, while 1.5 MMbbls are via swaps at an average price of $73.4/bbl. For 2027, EnQuest has a further c.3.6 MMbbls of production hedged utilising swaps at an average price of $64.4/bbl and in 2028, an additional 0.9 MMbbls hedged using swaps at an average price of $64.6/bbl.

· EnQuest is pleased to appoint Peel Hunt and Shore Capital as corporate brokers, alongside JP Morgan Cazenove.

Production and financial information

Notes:

1 Including realised losses of $28.5 million (2025: realised gains of $1.0 million) associated with EnQuest's oil price hedges

2 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 32. Note, EnQuest defines net debt as excluding finance lease liabilities

3 Including unrealised losses of $79.0 million (2025: unrealised gains of $33.2 million) associated with EnQuest's oil price hedges,

4 Excludes foreign exchange impact of $(3.8) million (2025: $15.6 million)

- Ends -

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Notes to editors

This announcement has been determined to contain inside information. The person responsible for the release of this announcement is Kate Christ, Company Secretary.

ENQUEST

EnQuest is unlocking value from energy assets. Responsibly. As an independent energy company with operations in the UK North Sea and across South East Asia, the Group's strategic vision is to lead as a safe, efficient operator of mature and underinvested oil and gas assets; sustainably extending field lives and delivering superior value across the asset lifecycle, as part of a just energy transition.

EnQuest PLC trades on the London Stock Exchange.

Please visit our website www.enquest.com 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 41,544 Boepd (2025: 38,257 Boepd) in the first half of 2026, with the contribution from South East Asia rising to 41% of Group output (H1 2025: 22%). The production increase in the period was driven by strong underlying performance across the portfolio, the addition of Vietnam, and enhanced gas production in Malaysia, partially offsetting natural field declines and six weeks of unplanned production downtime at Magnus due to a third-party infrastructure outage. Without this unplanned third-party outage, production for the first half of 2026 would have been c.45.6 Kboed, with underlying Group production efficiency of 89%. 

UK operations

Magnus

In the first half of 2026, the Magnus field was shut in for six weeks due to unplanned downtime at the third-party-operated Ninian Central Platform ('NCP'), primarily caused by storm damage. This outage reduced EnQuest production by c.4.1 Kboed for the period.

Accordingly, average production at Magnus for the first six months of 2026 was 11,269 Boepd, 13% lower than the first half of 2025 (12,989 Boepd). Production efficiency for the first half of the year was 63% (2025: 73%). Excluding the impact of the third-party infrastructure outage, Magnus production efficiency for the period was 90%.

EnQuest is focused on fully eliminating Magnus' exposure to NCP, through its Ninian Bypass Project, which it is executing alongside Neo Next +, and which is scheduled to complete in 2027. Ahead of this, EnQuest continues to work collaboratively and proactively to minimise future asset disruption.

In H1 2026, in response to early-year disruption, the Group accelerated the start of the six-well Magnus drilling programme to May 2026. The first well in the programme, a producer well within the Lower Kimmeridge Clay Formation ('LKCF'), came online delivering expected rates in July.

A key operational priority for the second half of the year is the annual maintenance shutdown. The shutdown has a broad scope, focused on proactive asset integrity work and debottlenecking of production, including upgrades to both compressor trains and other rotating equipment key to Magnus operations. Upon completion of the shutdown, drilling activity will resume in September, with a workover in the LKCF, followed by the second well in the programme, from which first oil is expected in early 2027.

Kraken

Average net production of 9,161 Boepd (2025: 11,481 Boepd) in the first half of 2026 reflected a period of single train operations, which lowered average production efficiency to 87% (2025: 96%). The asset team used this period to proactively complete key maintenance work, enabling the fifteen-day maintenance shutdown originally planned for the second half of the year to be replaced by a three-day 'pit stop'. Following the successful completion of this work, the Kraken team is targeting full year production efficiency in excess of 90%, which would bring full year 2026 production volumes back in line with target. This would represent a continuation of exemplary asset performance.

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.

The Group is also advancing the Bressay gas import project as a subsea tie-back to Kraken and is engaged with new joint venture partner Harbour Energy on the project. 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 the use of hydrogenated vegetable oil as a replacement fuel to diesel, as well as 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.

EOR Project

Work to mature the Kraken Enhanced Oil Recovery ('EOR') project advanced materially during the period. Following the initial round of polymer testing reported in March, an improved polymer chemistry has been selected for the project. With the new polymer delivered ready-made and blended into the injection water in-line, the design is significantly simplified, reducing topsides complexity and lowering both facilities modification costs and polymer unit cost.

The work to ensure compatibility of reservoir chemicals with topside process equipment is complete. A specialist third-party laboratory tested the selected polymer within live Kraken fluids across the full range of production temperatures, including through the separation process on the FPSO, with positive results. Polymer injection-well modelling has also been completed for one Kraken drill centre and calibrated against empirical well data, confirming that the wells can accept polymer at the optimal reservoir viscosity, maximising the effectiveness of the polymer flood process.

The project is working toward its next decision stage gate in H2 2026, after which it is expected to move into front-end engineering design ahead of Final Investment Decision.

EOR continues to represent a significant material upside to Kraken's value, and the Group views the project in two phases. Phase 1, which involves a pilot polymer delivery at a single drill centre, is expected to add approximately 5 MMbbl of incremental recoverable oil and is the subject of the forthcoming investment decision. Phase 2, which represents full-field development, is currently estimated at 30 to 40 MMbbl gross.

Other Upstream assets

Production at the Greater Kittiwake Area ('GKA') for the first six months of 2026 averaged 1,593 Boepd (2025: 2,001 Boepd). The asset has reached a significant milestone, with well plugging and abandonment activities now progressing safely and efficiently in parallel with production operations. The integrated EnQuest and CB&I asset team continues to deliver solid production uptime of c.70%, ahead of expectations for an asset in the final 18 months of its production licence. This performance reflects the team's disciplined execution and exceptional safety culture, which is approaching 21 years without a lost-time injury.

Average net production at Golden Eagle was 2,455 Boepd (2025: 2,986 Boepd) in the first half of the year, with asset production efficiency of 95% (2025: 97%).

South East Asia operations

The Group's Malaysian footprint is poised to grow significantly through the acquisition of participating interests in four PSCs. The proposed acquisitions, which will elevate Group production above 100,000 Boepd, are expected to complete on 31 December 2026.

With all conditions precedent now satisfied, the key workstreams relate to transferring asset operations to EnQuest, with strong collaboration between EnQuest's Malaysia teams and PETRONAS Carigali.

Malaysia

PM8/Seligi

For the first six months of 2026, average production in Malaysia was 12,563 Boepd, up 49% versus 1H 2025 (8,427 Boepd). This increase was driven by the material incremental addition of Seligi 1b gas, which EnQuest brought online nine months early in December 2025, delivering c.6,200 Boepd of production in the first half of the year. EnQuest has continued to execute well work to enhance Seligi gas supply, with a proven ability to deliver up to 115 MMscfd of gas to support Peninsular Malaysian demand, which has consistently exceeded contracted levels. Additional gas well work is planned, including the completion of two wells in Q4 2026.

Core asset performance has remained strong, with 96% production efficiency, high levels of compressor availability, incremental gains from the idle well restoration ('IWR') programme, and robust base well performance.

Cendramas

EnQuest is preparing to assume a 25% non-operated participating interest in the Cendramas PSC, alongside Medco (50%, operator) and DIALOG (25%). The effective date of the Joint Operating Agreement is 23 September 2026. The Cendramas PSC consists of six discovered fields in an area approximately 140 kilometres off the coast of Peninsular Malaysia in shallow water depths of 60 to 70 metres. The PSC block includes c.20 MMboe of oil reserves from the existing producing fields, with a further c.10 MMboe associated with identified infill well opportunities. The base work programme also includes the development of the Cendor Graben field, which is estimated to hold 28 MMboe of reserves.

The existing producing fields are expected to deliver in excess of 5 Kboed on a gross basis in 2026 and 2027. Current volumes are produced across five platforms, a mobile offshore production unit ('MOPU') and a floating production storage and offloading vessel ('FPSO'), providing EnQuest with the opportunity to deploy its expertise in floating production hubs to benefit the PSC.

DEWA Project

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. Development planning has identified options for produced gas to be transported to the MLNG plant in Bintulu, via tie-in to adjacent platforms. The target is to have a draft field development and abandonment plan ('FDAP') in place by Q3 2026, in order to commence commercial negotiations.

Subject to Final Investment Decision ('FID'), the anticipated first gas date is dependent on ullage availability at the tie-in facility, as well as the MLNG plant. The initial development phase is targeted to deliver c.7 Kboed of gas production and c.24 MMboe of additional reserves. Other fields within the PSC area will also be considered for future phased development.

Vietnam

Block 12W

EnQuest's Block 12W acquisition, anchored by operatorship of a 53.125% equity interest in the Chim Sáo and Dua production fields, was completed in July 2025 with a cash consideration of $25.7 million. By deploying EnQuest's proven late-life asset management expertise to execute three proactive well investments in the second half of 2025, the Group boosted net average production in the fourth quarter to c.5.5 Kboed and achieved payback on the acquisition within 12 months.

H1 2026 performance has been in line with expectations, with net production of 4,395 Boepd for the period. This includes a significant extended planned shutdown to replace the FPSO swivel, which was completed within 20 days (six days ahead of schedule), with exemplary safety and cost management.

Following a proactive start to asset operatorship, EnQuest was awarded a four-year PSC extension, on the existing terms, in January 2026. This extension provides EnQuest and its joint venture partners with the opportunity to access upside across Block 12W and progress discovered resources into reserves, with prospectivity spread across three gas discoveries and several additional targets.

Brunei

Block C Project

Following the Block C PSC award in July 2025, with EnQuest as operator on a 100% working interest basis, work is progressing as planned to form a 50:50 Joint Venture Company between the Government of Brunei and EnQuest, with incorporation targeted by Q4 2026. Work is ongoing to finalise the resources and proposed development concept and ongoing FEED study 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.

Indonesia

Gaea & Gaea II PSCs

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. 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.

The focus of the JV is on maturing targets for further geological and geophysical study, including plans for a Full Tensile Gravity survey in 2027. Following an environmental baseline assessment, seismic reprocessing and future 2D seismic acquisition is expected be completed across both blocks, with the potential for high-impact exploration targeting large potential gas volumes in a frontier region.

Decommissioning

EnQuest's decommissioning team has delivered several key milestones in 2026, further reinforcing its position as a discipline leader in the North Sea.

The Thistle platform was safely and successfully disembarked for the final time in July, following almost 48 years of production operations. Further subsea work was also completed, covering essential inspection, repair and maintenance activities, as well as conductor recovery, utilising a bespoke tool, co-developed by EnQuest and designed specifically for the Thistle project. While this milestone marks the end of onboard habitation, the project focus is shifting to engineering and planning ahead of removal activities, which are scheduled to commence in 2027 with the topsides. The Thistle jacket will be removed in 2028.

The Heather topsides, which were removed in a heavy lift operation in August 2025, are currently being dismantled at the MARS yard in Denmark, with 97% of all decommissioning material set to be reused or recycled. The Heather jacket is currently scheduled for removal in 2028, which aligns with previously agreed contractual execution windows.

The Group has also commenced well plugging and abandonment ('P&A') work at GKA, alongside ongoing production. A Hydraulic Workover Unit has been installed on the Kittiwake platform, and well P&A operations are underway on the first of eight platform wells. This programme will continue into 2027. At Magnus, the Well Safe Defender rig has mobilised and has commenced proactive P&A activities on the subsea wells at Magnus South, following a successful intervention campaign using the Well Enhancer LWIV earlier in the year.

In Malaysia, the Group is on track to successfully complete the P&A of 14 wells across the Seligi field during 2026.

These achievements underscore EnQuest's commitment to operational excellence and environmental responsibility as it continues to execute complex multi-asset decommissioning campaigns, ahead of schedule and within budget.

Midstream

EnQuest operates the Sullom Voe Terminal ('SVT') on Shetland and around 1,000km of pipelines. Through the first half of 2026, SVT continued to deliver safe, stable and effective operations for all users, delivering 100% availability. This strong operational performance was delivered alongside a significant programme of transformation, decommissioning and major infrastructure investment.

EnQuest remains focused on right-sizing SVT for future operations, and good progress has been made on the project to connect the terminal to the UK's electricity grid. Construction of the New Stabilisation Facilities ('NSF') is nearing completion, while work is ongoing to decommission redundant legacy facilities, systematically removing deterioration and integrity risk from the terminal. This work is being delivered in a controlled and environmentally sensitive manner, supporting the transition to a smaller, lower-cost facility with a materially smaller carbon footprint.

Together, these projects will provide the resilience required to extend SVT operations, which support production at both East of Shetland and West of Shetland assets, whilst also retaining the potential for its repurposing for new business development, including the new energy projects managed by Veri Energy.

Veri Energy

Veri Energy continues to work on behalf of EnQuest across a number of decarbonisation and renewable energy initiatives.

Plans to develop an onshore wind farm at the SVT continued to progress through the first half of 2026. This project harnesses Shetland's natural advantage of having one of the world's highest wind capacity factors and utilises existing terminal infrastructure to support decarbonisation and reduce operating costs at the site.

Plans for net-zero e-fuel production at SVT also advanced in the period, with the project securing almost £760,000 from the Scottish Government to support completion of the pre-FEED stage, recognising the strategic importance to the Government of developing low-carbon fuel production in Shetland and advancing the project towards the next phase of development.

EnQuest holds two carbon storage licences, CS013 and CS014, that incorporate the Magnus and Thistle fields (both EnQuest operated) and benefit from significant existing infrastructure connected to SVT. Through Veri, EnQuest continues to work on establishing a flexible merchant carbon storage business, providing a route for isolated emitters across the UK and Europe to permanently sequester CO₂. The project is based on transporting captured CO₂ by ship to SVT before onward transportation through repurposed pipeline infrastructure for permanent storage in depleted offshore oil and gas reservoirs.

Environmental, Social and Governance review

The health, safety and wellbeing of our people and delivering Safe Results is EnQuest's top priority. Pleasingly, the Group has completed all 2026 operations without any lost time incidents ('LTI'). EnQuest's commitment to safety is exemplified by key 2026 milestones: closing in on 21 years of LTI-free performance at the Greater Kittiwake Area and four years LTI-free now achieved in Malaysia.

EnQuest continues to make progress in reducing its absolute Scope 1 and 2 emissions and is delivering strongly against national emissions reduction targets and the Board-approved net zero commitment. As at 31 December 2025, EnQuest's UK Scope 1 and 2 emissions had reduced by 46% against the 2018 baseline, which is significantly ahead of the UK Government's North Sea Transition Deal target of achieving a 25% reduction in Scope 1 and 2 CO2 equivalent emissions by 2027 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% and continually screens emission reduction opportunities at all sites.

In South East Asia, EnQuest is executing a growth strategy that aligns regional economic expansion with a country-level structural shortfall in energy supply. To a large extent, natural gas is the transitional fuel bridging this gap with reduced emissions. EnQuest is therefore excited by the rapid growth being delivered in the region and continues to review all acquisitions in the context of lowering carbon emission intensity across the Group.

Financial Review

All figures quoted are in US Dollars unless otherwise stated.

Overview

In the six months to 30 June 2026, EnQuest delivered strong operational cashflows and announced a number of significant capital structure and transactional milestones. Tension in the Middle East drove a c. 22% rise in crude prices, Brent averaging $87.5/bbl, trading within a wide and volatile range. EnQuest production also grew by 9%, boosted to 41,544 boe/d by an expanded operational footprint in South East Asia - new oil production delivered from Block 12W (Vietnam) and new gas production from Seligi 1b (Malaysia).

Tempering this, the previously announced third party infrastructure disruption in the UK North Sea reduced H1 2026 Magnus production by c. 4,100 boepd, which resulted in one Magnus cargo being deferred beyond 30 June 2026, with a cash flow impact of c. $60 million. Despite this, cash generated by operations totalled $281.4 million (a 31% year-on-year increase) and underlying adjusted free cash flow totalled $71.3 million (a 118% year-on-year increase).

Alongside an organic program of capital expenditure totalling $78.3 million (H1 2025: $83.2 million), EnQuest completed a key balance sheet refinancing step and announced two significant transactions. In February, the Group settled the Magnus Contingent Consideration liability through a $60.0 million cash payment. This credit enhancing deal eliminated a c.$433 million balance sheet liability (as at 30 June 2025) and drove a 38% expansion in the Group's accessible RBL capacity. In April, EnQuest refinanced its bonds, reducing its borrowing costs by 175 basis points and further simplifying the Group capital structure. Costs associated with this refinancing totalled c.$35 million, inclusive of early redemption costs and an original issue discount which together totalled $20.0 million. In June EnQuest announced a step-change transformational transaction - the $833.0 million acquisition of interests in four Malaysian PSCs and paid a deposit and fees totalling $28.7 million.

After paying a $20.2 million dividend to shareholders in June, and reflecting the balance between payments made on these material strategic steps and the Group's strong underlying asset free cash flow, EnQuest's net debt at 30 June 2026 totalled $517.0 million (31 Dec 2025: $433.9 million) and the Group's net debt / adjusted LTM EBITDA ratio widened slightly to 1.0x (31 Dec 2025: 0.9x).

Income statement

Revenue

Group production averaged 41,544 Boepd (9% higher than in H1 2025: 38,257 Boepd) reflecting the contribution from Vietnam (which was acquired in July 2025) and additional gas volumes in Malaysia (Seligi 1b first gas having been delivered in December 2025, nine months ahead of schedule). This South East Asian growth was partially offset by lower UK production, primarily driven by the third-party related outage at Magnus. Oil accounted for c.75% of this output (H1 2025: c.86%).

Brent crude oil prices increased 22% year-on-year, to average $87.5/bbl (H1 2025: $71.8/bbl) while the average day-ahead gas price rose 7% to 107p/therm (H1 2025: 100p/therm). Excluding the impact of hedging, EnQuest realised an average oil price of $89.6/bbl (H1 2025: $70.8/bbl). Post-hedging, the realised oil price was $84.5/bbl (19% higher than in H1 2025 ($71.0/bbl)).

Reported Group revenue for H1 2026 totalled $529.9 million (H1 2025: $549.1 million). Realised losses on commodity hedges totalled $28.5 million (2025: gains of $1.0 million). Unrealised losses on open commodity contracts (primarily from mark-to-market movements on swap contracts) resulted in a non-cash charge of $79.0 million (2025: unrealised gains of $33.2 million), reflecting the timing at which the hedges were enacted and oil price volatility. Revenues, adjusted to exclude unrealised non-cash losses on open commodity contracts, increased 18% to $608.8 million (2025: $515.9 million).

Oil revenues in H1 2026 were $500.1 million (24% higher year-on-year, H1 2025: $404.0 million), and condensate and gas contributed $135.2 million (25% higher year-on-year, H1 2025: $108.2 million). Revenue from onward sale of gas purchases from third-party West of Shetland fields is offset through a related charge to cost of sales.

For the period September to December 2026, the Group has c.2.2 MMbbls of production hedged. Of these 0.6 MMbbls are via collars with an average floor price of $50.2/bbl and an average ceiling price of c.$89.5/bbl, while 1.5 MMbbls are via swaps at an average price of $73.4/bbl. For 2027, EnQuest has a further c.3.6 MMbbls of production hedged utilising swaps at an average price of $64.4/bbl and in 2028, an additional 0.9 MMbbls hedged using swaps at an average price of $64.6/bbl.

Note: For the reconciliation of realised oil prices see 'Glossary - Non-GAAP measures' starting on page 32

Cost of sales1

Reported cost of sales totalled $480.4 million (24% higher than in H1 2025: $388.9 million), including operating costs of $227.9 million (25% higher than in H1 2025: $182.8 million).

The increase in cost of sales was primarily driven by $37.6 million movement in foreign exchange and UKA derivative positions (2026: net losses of $10.5 million; 2025 net gains of $27.1 million), $31.0 million higher production costs (2026: $187.4 million; 2025: $156.4 million) and a $14.4 million movement in the Group's lifting and hydrocarbon inventory position (2026: $12.9 million charge; 2025 $1.5 million credit).

H1 2026 production costs include $25.1 million associated with Block 12W in Vietnam following its acquisition in July 2025 and $7.7 million higher diesel costs across the Group. Adjusting for these items, underlying production costs were 1% lower year-on-year.

Unit operating costs were negatively impacted by $2.7/Boe as a result of Magnus downtime, with unit operating costs in H1 2026 rising to $30.3/Boe (2025: $26.4/Boe).

Depletion expense ($118.3 million) was 5% lower than H1 2025 ($124.0 million), while other costs of operations increased $9.0 million to $110.1 million. 

Notes:

1 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 32

2 Calculated using production on a working interest basis

3 Includes realised loss/(gain) on derivatives

Impairment

In the period, the Group recognised a non-cash net impairment reversal of $29.6 million (2025: $0.5 million). This represents reversals of $22.3 million at Kraken, $2.9 million for GKA and $4.5 million for Golden Eagle, and was primarily driven by an increase in short-term oil price assumptions (reflecting market dynamics).

Other income and expenses

The Group has recognised net other income in the period of $7.9 million (2025: net expense of $18.0 million).

A stronger US Dollar in H1 2026 resulted in a non-cash foreign exchange revaluation gain of $5.3 million (2025: $28.9 million foreign exchange revaluation loss) and a net decrease in the decommissioning provision of fully impaired non-producing assets of $8.1 million (2025: non-cash charge of $17.5 million), while lease income totalled $9.8 million (2025: $8.7 million).

These credits have been largely offset by recognition of a net $14.4 million provision following receipt of a sanction notice from the NSTA in relation to the timing of the plugging and abandonment of 33 young and inactive wells across four licences. EnQuest has strongly disputed the fine, formally lodging an appeal against the sanction notice with the First Tier Tribunal. The Group is widely regarded as the UK North Sea's leading decommissioning operator and has a strong focus on safety, prioritising work on the basis of asset integrity to minimise the risk to human life and the environment.

The Group has recognised a net $4.4 million non-cash charge related to the aggregate change in fair value of the remaining Magnus decommissioning-linked contingent consideration, primarily driven by a lower discount rate (2025: $14.9 million non-cash credit to the Magnus contingent consideration driven by lower oil prices).

Adjusted EBITDA

Adjusted EBITDA for the period totalled $273.0 million, a 13% year-on-year increase, driven by the balance between higher oil prices and production growth in South East Asia, deferred production at Magnus and movements in FX.

EnQuest's net debt to adjusted LTM EBITDA ratio at 30 June 2026 equalled 1.0x (31 December 2025: 0.9x).

Note:

1 See reconciliation of Adjusted EBITDA within the 'Glossary - Non-GAAP measures' starting on page 32

Finance costs

Net finance costs in the period totalled $108.6 million (H1 2025: $73.2 million). Adjusting for the impacts of the Group's successful $675.0 million US Dollar bond refinancing in April 2026 (being the early redemption fee ($13.5m) and write-off of remaining unamortised fees relating to the previous High yield bond ($4.6 million), underlying finance costs were $90.5 million.

The increase in underlying finance costs compared to H1 2025 is primarily related to the Group's refinancing of its RBL in September 2025 and the US Dollar bond in April 2026, with overall interest charges of $46.5 million (2025: $36.1 million) and amortisation of capitalised financing fees of $11.3 million (2025: $6.1 million).

Finance charges also included: the unwinding of discounting on decommissioning and other provisions of $20.2 million (2025: $17.0 million); lease liability interest costs of $12.3 million (2025: $11.4 million); and other financial expenses of $3.7 million (2025: $7.8 million), which are primarily comprised of the cost for surety bonds that provide security for decommissioning liabilities.

Finance income totalled $3.4 million (2025: $5.2 million), primarily representing interest on cash held on deposit.

Profit/loss before tax

The Group's reported loss before tax was $24.8 million, which included non-cash unrealised losses on derivative contracts of $94.7 million (2025: profit of $65.6 million, which included non-cash unrealised gains on derivative contracts of $57.7 million). On an adjusted basis, the Group reported a pre-tax profit of $54.6 million (2025: loss of $5.3 million) (see the 'Glossary - Non-GAAP measures' starting on page 32).

Taxation

The 2026 half year tax charge was $15.1 million. Current cash tax charges of $52.1 million includes $23.7 million in relation to the UK Energy Profits Levy and $28.4 million in relation to income taxes in South East Asia. Non-cash deferred tax credits totalled $37.0 million, and these primarily reflect tax credits on unrealised hedge losses partially offset by the utilisation of EnQuest's strategic UK North Sea tax asset in the period.

The Group's overall effective tax rate in the period equalled (60.9)%, largely driven by corporate losses for which no deferred tax asset has been recognised (period ended 30 June 2025: 364.6% inclusive of the $123.9 million one-off charge for the two-year EPL extension). 

At 30 June 2026, the Group has c.$3 billion of cumulative UK ring-fence Corporation Tax losses and c.$1.6 billion of cumulative Supplementary Corporation Tax losses. Given the Group's current operating structure and production portfolio, deferred tax assets have been recognised for $1,786.1 million gross ring-fence Corporation Tax losses and $635.6 million Supplementary Corporation Tax losses (31 December 2025: $1,851.3 million and $726.2 million, respectively).

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 South East Asian assets.

Profit/loss for the period

EnQuest reported a statutory net loss of $39.9 million (2025: statutory net loss of $173.5 million). On an adjusted basis (see 'Glossary - Non-GAAP measures' starting on page 32), EnQuest's net loss reduced to $9.0 million (2025: adjusted net loss of $38.9 million).

Earnings per share

The Group's reported basic loss per share was 2.1 cents (2025: loss of 9.3 cents) and reported diluted loss per share was 2.1 cents (2025: loss of 9.3 cents).

Cash flow, EnQuest net debt and liquidity

Reflecting higher production and commodity prices, reported net cash flows from operating activities for the period increased 24% to $238.8 million (H1 2025: $191.9 million).

Reported net cash flows used in investing activities increased year-on-year by $81.8 million, to $165.6 million. This figure includes several one-off costs, principally a $60.0 million payment associated with the previously reported settlement of the Magnus contingent consideration profit sharing agreement and a $28.7 million deposit and fee payment associated with the planned acquisition of participating interests in four offshore PSCs in Malaysia. The H1 2025 figure included the payment of a $3.6 million deposit in relation to the Vietnam asset acquisition.

Excluding these impacts, net cash flows used in investing activities were broadly flat year-on-year reflecting organic capital expenditure - detailed below:

Having refinanced its RBL Facility in Q4 2025, which extended its maturity to 2031, EnQuest took further steps in H1 2026 to strengthen its balance sheet in support of transformational transactional growth. The Group utilised $132.1 million of cash in financing activities (2025: $73.3 million).

In April 2026, EnQuest successfully refinanced its bonds - simplifying its capital structure and lowering borrowing costs. Through this capital markets action, and reflecting significant investor interest, the bonds were upsized to $675.0 million with the annual interest rate reduced to 9.875% and maturity extended to 2031. Proceeds were used to repay the existing $465.0 million 11.625% High yield bond (due November 2027) and the associated interest due ($27.0 million), the existing £133.0 million 9.00% retail bond (due October 2027) and related refinancing fees. Costs associated with this refinancing totalled c.$35 million, with $32.6 million paid as at 30 June 2026 inclusive of early redemption costs and an original issue discount together totalling $20.0 million.

In June 2026, the Group exercised an accordion option to increase the committed secured credit facility component of the Group's RBL Facility by $300.0 million to $700.0 million, incurring fees of c.$7.5 million. This provided 'funds certainty' for the transformational Malaysian acquisition. As at 30 June 2026 this facility remained undrawn.

In aggregate, EnQuest repaid a net $33.4 million of loans, borrowings and bonds in the period (H1 2025: net drawings of $21.0 million, primarily from a vendor loan).

In June 2026, EnQuest paid a dividend of $20.2 million, while interest payments on the Group's borrowings totalled $16.8 million, noting $27.0 million of interest was net settled as noted above (H1 2025: $15.3 million dividend and $43.6 million interest). $46.8 million was paid in relation to finance leases (H1 2025: $35.4 million), with the increase reflecting lease costs in Vietnam following acquisition in July 2025.

Adjusted free cash flow generation in H1 2026 was $71.3 million, which was 118% higher than the same period in 2025 ($32.7 million). This increase primarily reflected higher revenue, driven by higher production and commodity prices, noting the third-party infrastructure outage that impacted Magnus production resulted in deferral of a Magnus cargo to beyond the first half of 2026 (valued at approximately $60.0 million).

In aggregate and reflecting the combination of strong free cash flow and the aforementioned strategic transactions, EnQuest's cash and cash equivalents decreased by $62.7 million in the first half of 2026. EnQuest ended the period with $206.2 million of cash and cash equivalents (31 December 2025: $268.9 million), while cash and available undrawn facilities at 30 June 2026 grew 12% to $758.6 million (31 December 2025: $678.6 million), with the increase primarily reflecting a 38% expansion in the borrowing base amount post settlement of the Magnus Contingent Consideration liability.

The movement in EnQuest net debt was as follows:

Note:

1 Includes $27.0 million of interest on the USD High yield bond 11.625% that was net settled from proceeds of the USD bond 9.875%

2 See reconciliation of alternative performance measures within the 'Glossary - Non-GAAP measures' starting on page 32.

Note:

1 See reconciliation of EnQuest net debt within the 'Glossary - Non-GAAP measures' starting on page 32

Balance sheet

EnQuest remains committed to maintaining a strong and flexible balance sheet through a proactive and disciplined approach to capital management. This unwavering focus has enabled the group to deliver a step-change in its South East Asian operations, through the acquisition of participating interests in four PSC's in Malaysia.

Assets

Total assets at 30 June 2026 of $3,525.8 million remained in line with 31 December 2025 ($3,594.3 million). Driving this were: a decrease of $45.4 million in other financial assets including the closing mark-to-market valuation of the Group's open commodity and foreign exchange contracts; and lower cash and cash equivalents of $62.7 million; partially offset by $41.3 million higher trade and other receivables.

Liabilities

Total liabilities of $3,057.0 million are in line with the 31 December 2025 ($3,066.3 million). The main offsetting movements are: $55.7 million lower contingent consideration liabilities primarily reflecting the February 2026 payment to bp in settlement of the Magnus Contingent Consideration profit share liability; an increase in other financial liabilities of $48.9 million reflecting the closing mark-to-market valuation of the Group's open commodity and foreign exchange contracts.

Total income tax liabilities, excluding deferred tax, increased by $44.8 million in the period to $161.3 million (31 December 2025: $116.5 million), with $133.1 million in current liabilities and $28.2 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 2025 Annual report.

Going concern disclosure

The interim financial statements have been prepared on the going concern basis.

During the first half of 2026, EnQuest delivered several capital structure and transactional activities, including:

· The $60 million payment to settle the Magnus Contingent Consideration profit share liability in February, which unlocked the full upside of one of EnQuest's core assets and drove a 38% expansion in the Group's accessible RBL capacity;

· In April, EnQuest issued new US Dollar bonds of $675 million, allowing it to repay both the previous High yield and retail bonds, lowering borrowing costs and further simplifying the Group's capital structure with maturity extended to 2031; and

· Announcing the acquisition of participating interests in four offshore Malaysian production sharing contracts doubling the Group's production and diversifying its asset base. This was accompanied by the exercise of an accordion option to increase the committed secured credit facility component of the Group's existing RBL Facility by $300.0 million to $700.0 million in order to provide certainty of funds for the $554 million upfront consideration.

Following satisfaction of all conditions precedent relating to the Malaysian acquisitions in August 2026, the Group is working towards completion of the transaction on 31 December 2026. As such, the impacts of financing the outstanding upfront consideration and the significant contribution to Group cash flows from 1 January 2027 have been incorporated into this going concern assessment.

EnQuest closely monitors and manages its funding position and liquidity requirements throughout the year, including forecast covenant results. Cash forecasts are regularly produced and discussed, with sensitivities considered for, but not limited to, changes in crude oil prices (adjusted for hedging undertaken by the Group), production rates and costs. These forecasts and sensitivity analyses allow management to mitigate liquidity or covenant compliance risks in a timely manner. Management have considered the impact of the ongoing situation in the Middle East, particularly on future oil prices. Reflecting the uncertainty as to how long the conflict and the period of elevated oil prices will last, management have assumed in the Base Case that the average oil price for the remainder of 2026 will be $80/bbl and then $75/bbl for the remainder of the going concern period. These figures reflect current trading conditions, which are slightly higher than those prices used in its impairment assessment (see note 2), but are considerably below current spot prices.

The Group's latest forecast and long-term plan underpins management's base case ('Base Case'), upon which a reverse stress test has been performed. This indicates that an oil price of c.$49/bbl is required to maintain covenant compliance over the going concern period, including settlement of any acquisition costs associated with the Groups Malaysian acquisition.

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 $72.0/bbl for the remainder of 2026 and $67.5/bbl for 2027;

· Production risking of 5.0%; and

· 2.5% increase in operating costs.

The Base Case and Downside Case indicate that the Group is able to operate as a going concern and remain covenant compliant for 12 months from the date of publication of its half-year results (the "going concern period").

After making appropriate enquiries and assessing the progress against the forecast, the Directors have a reasonable expectation that the Group will continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing these interim financial statements.

Risks and uncertainties

The Directors have reviewed the principal risks facing the Company and concluded the principal risks for the remaining six months of the financial year are unchanged from those described in the 2025 Annual Report and Accounts, which was published in April 2026. 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 and its acquisition of participating interests in Malaysia.

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.

· 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.

· 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 the integration of acquired assets, field development, decommissioning, decarbonisation and renewable energy opportunities.

· Reserves estimation and replacement

· Failure to develop contingent and prospective resources or secure new licences and/or asset acquisitions and realise their expected value.

· Prices and foreign exchange

· 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 and gas prices. This risk also includes the potential impacts of climate change on oil and gas supply and demand and recognises that other macroeconomic factors, such as foreign exchange and carbon pricing, could present a material risk to the business.

· Access to capital and liquidity

· Inability to fund financial commitments or maintain adequate cash flow and liquidity and/or reduce costs.

· Significant reductions in the oil price, production and/or the funds available under the Group's RBL facility would likely have a material impact on the Group's ability to repay or refinance its existing credit facilities and invest in its asset base. Prolonged low oil prices, cost increases, including those related to an environmental incident, and production delays or outages, could threaten the Group's liquidity and/or ability to comply with relevant covenants.

· Political, regulatory and fiscal environment, including climate change risk

· Unanticipated changes in the political, regulatory or fiscal environment, including those associated with climate change, can affect the Group's ability to deliver its strategy/business plan and potentially impact revenue and future developments.

· 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.

Group Income Statement

For the six months ended 30 June 2026

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.

The attached notes 1 to 15 form part of these condensed Group financial statements.

(i) Inclusive of a deferred tax credit of $37.0 million (2025: $189.3 million charge). A $123.9 million charge from the two-year extension to the UK Energy Profits Levy enacted in March 2025 was included in the six months to 30 June 2025.

Group Balance Sheet

At 30 June 2026

(i) Decommission provision includes EnQuest's share of the total Block 12W decommissioning liability noting $92.6 million has been pre-funded through an abandonment fund held in Vietnam which is disclosed within non-current other receivables

The attached notes 1 to 15 form part of these condensed Group financial statements.

Group Statement of Changes in Equity

For the six months ended 30 June 2026

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 2026

(i) Other financial expenses paid includes cash payments for High yield bond and RBL refinancing fees

(ii) Restricted cash at 30 June 2026 includes $1.8 million for Indonesia performance bond (31 December 2025: $1.8 million) and $0.7 million remaining in accounts relating to 2025 decommissioning security agreement obligations (31 December 2025: $1.2 million) and $3.2 million held on deposit relating to commodity trading activities

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 2026

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 2026 were authorised for issue in accordance with a resolution of the Board of Directors on 2 September 2026.

2. Basis of preparation

The interim condensed consolidated financial statements of the Group for the six months ended 30 June 2026 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 2025.

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 2025, on which the auditor gave an unqualified audit report, have been filed with the Registrar of Companies.

The Group continues to present various Alternative Performance Measures ('APMs') when assessing and discussing the Group's financial performance, balance sheet and cash flows that are not defined or specified under IFRS but consistent with the measurement basis applied to the financial statements. The Group uses these APMs, which are not considered to be a substitute for, or superior to, IFRS measures, to provide stakeholders with additional useful information to aid the understanding of the Group's underlying financial performance, balance sheet and cash flows by adjusting for certain items, which impact upon IFRS measures or, by defining new measures. See the Glossary - Non-GAAP Measures on page 32 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 2026 are materially consistent with those followed in the preparation of the Group's financial statements for the year ended 31 December 2025. 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 2025 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. Two judgements disclosed in the Group's 2025 annual report and accounts are no longer required, being the 75% Magnus acquisition contingent consideration following settlement and the conclusion that the Vietnam acquisition was to be accounted for as a business combination under IFRS3. Other key changes to the remaining judgements and estimates 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 2026. Forecasts for the remainder of 2026 and FY 2027 were increased to reflect elevated oil prices that have risen in response to the ongoing geopolitical unrest in the Middle East. The long-term assumptions for 2028 and beyond are unchanged from that disclosed in the Group's 2025 annual report and accounts. See the table below for summary of oil price assumptions used at 30 June 2026. The price assumptions used at the end of 2025 were $65.0/bbl (2026), $67.5.0/bbl (2027), $72.5/bbl (2028), $75.0/bbl (2029) and inflated at 2% per annum from 2030. See note 7 for oil price sensitivities.

*Inflated at 2% from 2030

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.

3. Segment information

Segment information for the six month period is as follows:

(i) Gains and losses (see note 9(b)) on derivatives and finance income and costs 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):

(i) Includes $27.8 million realised losses (2025: $10.6 million realised gains) on derivatives and $94.7 million unrealised losses (2025: $57.7 million unrealised gains) on derivatives

4. Revenue and other operating income/(expense)

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.

(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 32

5. Income tax

The major components of income tax expense/(credit) are as follows:

(b) Reconciliation of total income tax charge

A reconciliation between the income tax charge and the product of accounting (loss)/profit multiplied by the UK statutory tax rate is as follows:

(i) Predominantly in relation to non-deductible movements in other provisions and Magnus decommissioning linked-contingent consideration

(ii) This charge consists of an EPL current tax charge of $28.2 million (30 June 2025: $42.4 million) and deferred EPL credit of $34.9 million (30 June 2025: $6.3 million charge).

(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:

(i) Predominantly includes $107.7 million on deferred income (see note 24 in the Group's 2025 Annual Report and Accounts). The remaining balance in Other temporary differences is largely related to an asset associated with unrealised hedging losses and an asset associated with deferred PRT

(ii) The total amounts for EPL included in net deferred assets are a deferred tax liability of $251.0 million for accelerated capital allowances and a deferred tax asset of $69.3 million for other items, which predominantly includes $52.5 million related to deferred income (see note 24 in the Group's 2025 Annual Report and Accounts). The remaining asset arises largely in respect of unrealised hedging losses

Reconciliation of net deferred tax assets/(liabilities)

(d) Tax losses

At 30 June 2026, the Group has c.$3 billion of cumulative UK ring-fence Corporation Tax losses and c.$1.6 billion of cumulative Supplementary Corporation Tax losses. These are held by EnQuest's two UK operational subsidiaries. Deferred tax assets are recognised to the extent that taxable profits are expected to arise in the future against which these tax losses can be utilised.

Given the Group's current operating structure and production portfolio, deferred tax assets have been recognised for $1,786.1 million gross ring-fence Corporation Tax losses and $635.6 million Supplementary Corporation Tax losses (31 December 2025: $1,851.3 million and $726.2 million, respectively), while there remains $1,118.3 million of UK ring-fence Corporation Tax losses available and $993.2 million of Supplementary Corporation Tax losses (31 December 2025: $1,117.5 million and $992.4 million, respectively) for which a deferred tax asset has not yet been recognised.

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). Neither a 10% reduction or increase in oil price would result in a change in recognition of the existing deferred tax asset.

The Group also has unused UK mainstream corporation tax losses of $684.8 million (31 December 2025: $578.4 million) for which a deferred tax asset has not been recognised. A deferred tax asset has also not been recognised for the adjustment to bond valuations on the adoption of IFRS 9. The benefit of this bond deduction is instead taken over ten years, with a deduction of $1.1 million made in the current period and the remaining $3.1 million benefit unrecognised (31 December 2025: $4.2 million).

Further, the Group has unused Malaysian income tax losses of $16.0 million (31 December 2025: $16.3 million) arising in respect of the Tanjong Baram RSC for which no deferred tax asset is recognised, due to uncertainty of recovery of these losses.

No deferred tax has been provided on unremitted earnings of overseas subsidiaries. The Finance Act 2009 exempted foreign dividends from the scope of UK corporation tax where certain conditions are satisfied.

(e) Changes in legislation

In the Finance Bill 2024-2025 the UK Government legislated various changes to the EPL, including an extension to 31 March 2030 (previously 31 March 2028) to which the EPL applies. The impact on the prior period financial statements tax charge and deferred tax for EPL was $123.9 million.

The 2025 Autumn Budget announced a permanent revenue-based Oil and Gas Levy to replace EPL. The Levy will be implemented in a future Finance Bill with draft legislation being published on 13 July 2026. The Levy will apply at a rate of 35% to realised oil and gas revenues earned above specified thresholds (initially set at $90 per barrel for oil and 90 pence per therm for gas, and to be adjusted annually in line with CPI inflation). The Levy will take effect the day after EPL ceases, being the earlier of 31 March 2030 or the point at which the energy security investment mechanism is triggered. As at the reporting date, the implementing legislation remains draft and has not been substantively enacted, therefore the proposed legislative changes have had no impact on the Group's tax charge, deferred tax balances or results for the interim period.

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 2026, the Group held 20,000,000 (30 June 2025: 25,000,000) 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 2026.

Basic and diluted earnings per share are calculated as follows:

(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

Impairments

Impairments to the Group's producing assets and reversals of impairments are set out in the table below:

(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 net impairment reversal recognised in the six months to 30 June 2026 of $29.6 million relates to producing assets in the UK North Sea and is primarily driven by an increase in short-term oil price assumptions reflecting market dynamics (see note 2). The reversal is made up from $22.3 million at Kraken, $2.9 million for GKA and Scolty/Crathes and $4.5 million for Golden Eagle.

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 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.

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 reduction in the carrying amount of EnQuest's oil and gas properties of approximately $165.1 million, which is approximately 7% of the net book value of property, plant and equipment as at 30 June 2026.

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 9.0% 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 reversal recognised in the first half of 2026 would have been approximately $16.5 million lower. If the discount rate was 1.0% lower, the net impairment reversal recognised would have been approximately $1.6 million higher.

8. Loans and borrowings

The Group's borrowings are carried at amortised cost as follows:

(i) Accrued interest includes vendor loan facility interest accruals of $2.3 million (31 December 2025: $1.9 million) and bond interest accruals of $16.2 million (31 December 2025: $8.9 million)

In April 2026, the Group issued a new 9.875% US Dollar bond. The principal of the new bond raised totalled $675.0 million and is repayable in April 2031. The above carrying value includes the principal less the remaining unamortised original issue discount of $6.3 million and fees of $15.7 million. The net proceeds were used to repay the USD High yield bond 11.625% in April and the GBP Retail bond 9.00% in May. The remaining unamortised fees of the previous USD High yield bond of $4.6 million, and the related early termination fee of $13.5 million, were expensed within finance costs.

In June 2026, the secured revolving loan facility commitment within the Group's existing RBL Facility was extended from $400.0 million to $700.0 million following the exercise of the accordion option to provide certainty of funds in connection with the expected acquisition of participating interests in four offshore production sharing contracts in Malaysia, for which all conditions precedent were satisfied in August.

There was no loan drawdown under the Group's RBL at 30 June 2026 (31 December 2025: $nil). With no RBL loan drawdown the increase in committed funds and an increase in the Group's existing asset borrowing base, which included the positive impact from the Magnus Contingent Consideration settlement with bp, $552.4 million was available for drawdown at 30 June 2026. Letters of credit utilisation was $299.0 million. The full $700.0 million committed facility will be available at the time of completion of the Malaysian PSC acquisitions.

9. Other financial assets and financial liabilities

(a) Summary as at 30 June 2026

(b) Income statement impact

The (expense)/income recognised for derivatives are as follows:

(c) Fair value measurement

(i) Amortised cost is a reasonable approximation of the fair value, carrying value includes accrued interest

(ii) Carrying value includes accrued interest and related fees

(iii) Amounts included in the Total column exclude related fees

Fair value hierarchy

All financial instruments for which fair value is recognised or disclosed are categorised within the fair value hierarchy, based on the lowest level input that is significant to the fair value measurement as 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 (2025: 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

75% Magnus acquisition contingent consideration

In February 2026, an agreement was concluded with bp for EnQuest to settle the profit share arrangement for $60.0 million, with payment made in the same month. At 30 June 2026, the contingent consideration for Magnus was $nil reflecting full settlement of the obligation (31 December 2025: $60.0 million, noting that as the agreement was substantially agreed at 31 December 2025, this value was used to fair value the contingent consideration).

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 2026, the amount due to bp, calculated on an after-tax basis by reference to 30% of bp's decommissioning costs on Magnus, was $28.9 million (31 December 2025: $24.6 million). Any reasonably possible change in assumptions would not have a material impact on the provision.

11. Provisions

(i) Changes in estimates includes foreign exchange movements

(ii) Includes $10.6 million related to producing assets disclosed in note 7 and $9.0 million relating to assets in decommissioning recognised in the income statement

(ii) Utilisation differs to amounts paid in the cashflow statement due to movements in accruals recognised within trade and other payables

Decommissioning provision

The Group's total provision represents the present value of decommissioning costs which are expected to be incurred up to 2050, assuming no further development of the Group's assets. The Group's decommissioning provision has decreased by $17.5 million in the period. This primarily reflects lower cost estimates of $19.6 million, predominantly due to a stronger US Dollar, together with the ongoing decommissioning programmes utilisation of $17.8 million. At 30 June 2026, an estimated $329.1 million is expected to be utilised between one and five years (31 December 2025: $364.3 million), $345.2 million within six to ten years (31 December 2025: $373.1 million), and the remainder in later periods.

The Group uses Letters of Credit, surety bonds and cash deposits to provide security for its decommissioning obligations. The Group utilised Letters of Credit totalling $299.0 million (31 December 2025: $381.5 million) and surety bonds of $119.2 million (31 December 2025: $nil) to provide security for its decommissioning obligations at 30 June 2026.

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 sensitivity has only been run for the UK North Sea segment given its materiality compared to Malaysia and Vietnam. 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 $58.2 million. The pre-tax impact on the Group income statement would be a charge of approximately $31.2 million, reflecting the change in estimates for assets which have already ceased production.

Thistle decommissioning provision

At 30 June 2026, the amount due to bp by reference to 7.5% of bp's decommissioning costs on Thistle and Deveron was $14.5 million (31 December 2025: $15.3 million), with the reduction mainly reflecting the utilisation in the period offset partly from an increase in the fair value due to a lower discount rate. Unwinding of discount of $0.3 million is included within finance costs for the period ended 30 June 2026 (30 June 2025: $0.4 million).

Other provisions

Following previously disclosed discussions, in April 2026 the North Sea Transition Authority ('NSTA') issued a gross fine of £16.5 million ($22.3 million) on a subsidiary of the Group for non-compliance in relation to the timing of plugging and abandonment ('P&A') of 33 inactive wells across its North Sea asset portfolio. A provision of $22.3 million has been recorded, with the Group's net share of $14.4 million recorded in the income statement within other expenses and the remaining $7.9 million recognised in trade and other receivables representing EnQuest's partner share of these costs. EnQuest has strongly disputed the fine on a number of grounds and lodged an appeal with the First Tier Tribunal.

12. Commitments and contingencies

Capital commitments

At 30 June 2026, the Group had commitments for future capital expenditure amounting to $112.1 million (31 December 2025: $48.4 million). This predominantly relates to life of field minimum work commitments under the Cendramas PSC which was signed in April 2026 and effective in September 2026, the development of the non-associated gas resources in the PM8/Seligi PSC contract area under the Seligi 1b gas agreement and the new stabilisation facility at Sullom Voe Terminal. Where the commitment relates to an operated 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 2026, the Group utilised Letters of Credit totalling $299.0 million (31 December 2025: $381.5 million) and surety bonds of $119.2 million (31 December 2025: $nil) 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 or disclosed, 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