Interim report
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RNS Number : 4027SJadestone Energy PLC27 August 2026 2026 Half Year Results 27 August 2026 - Singapore: Jadestone Energy plc (AIM:JSE) ("Jadestone" or the "Company"), an independent upstream production and development company and its subsidiaries (the "Group"), focused on the Asia-Pacific region, reports its unaudited condensed consolidated interim financial statements, as at and for the six-month period ended 30 June 2026 (the "financial statements"). Management will be hosting a webcast at 9:00 a.m. UK time today, details of which can be found in the announcement below. T. Mitch Little, Chief Executive Officer of Jadestone, commented: "With the first half of 2026 now in the rear-view mirror, I am pleased with the progress we've made on bolstering the foundations of our underlying business. We have enhanced the financial strength of the platform through our debt refinancing, delivered material progress on our key Vietnam growth project, and delivered a very successful infill drilling program offshore Malaysia. More broadly, we are beginning to see signs of the hard work our teams are doing to instill operational excellence across the operated portfolio. While I recognize we need to demonstrate sustainable long-term performance before declaring full success, it's encouraging to see that our collective focus is beginning to translate into a stronger and more resilient business. Most notably, we are seeing meaningful improvements in operating performance at Montara. We have also delivered the Malaysia drilling program more than 20% below budget, while setting drilling records in the process. Both examples provide concrete evidence of the operational standards we are working to embed across the entire business. Notwithstanding the positive momentum in the business, our performance in the first half was affected by two key external events, a delayed production restart at CWLH following the dry dock maintenance campaign, and the impact of Cyclone Narelle on our operated Stag field. These events, combined with the sale of our Thailand assets in April 2025, represent the bulk of the period-on-period production decline in the first half. We now have defined plans in place to reinstate production at both CWLH and Stag. Looking ahead, we remain focused on maintaining our positive operational momentum while progressing the next phase of growth. In Vietnam, we remain on track to take final investment decision on the Nam Du/U Minh development by the end of 2026, with the farm-out process progressing to final negotiations with a select short list of interested counterparties." H1 2026 Operational Summary l Continued excellent safety and environmental performance, with Group[1] operations achieving an aggregate 13.6 million manhours lost-time injury free. l The three well infill campaign on the PM323 PSC offshore Malaysia was delivered safely and successfully, increasing field production by over three times the rates seen immediately prior to commencement of drilling operations. The campaign was delivered more than 20% below budget and set a record for the ERD ratio[2] ofany well drilled across all basins in Malaysia. l The Vietnam Government approved the Field Development Plan ("FDP") for the Nam Du/U Minh gas discoveries offshore Vietnam in March 2026, with signing of the Gas Sales and Purchase Agreement ("GSPA") in April2026. Subsequently, ~32 mmboe of gross 2P reserves were booked for the initial phase of the project. l Production of 15,282 boepd (H1 2025: 20,368 boepd), with first half production impacted by unplanned downtime at the Stag field due to the impact of Cyclone Narelle and planned maintenance activities associated with theCWLH FPSO dry dock and subsequent delays in reconnecting the FPSO and restarting production. H1 2026 Financial Summary l In March 2026, the Group successfully completed a US$200.0 million senior secured bond issue with maturity in 2031 and a coupon of 12%. The proceeds of the bond were partly used to repay the Group's reserve-basedlending ("RBL") facility. l Revenue before hedging increased 13% to US$261.1 million (H1 2025: US$231.0 million). Following the inclusion of a US$27.1 million hedging charge (H1 2025: US$2.7 million), revenue after hedging wasUS$234.0 million, an increase of 3% (H1 2025: US$228.3 million).
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l Adjusted unit operating costs[3] of US$37.64/boe (H1 2025: US$26.25/boe), with the period-on-period increase explained by lower production during the period and higher costs related to repair and maintenance activity atStag and CWLH and increases in fuel costs due to higher oil prices. l Adjusted EBITDAX3 of US$101.6 million (H1 2025: US$100.6 million). l H1 2026 loss after tax of US$4.8 million (H1 2025: profit after tax of US$37.6 million), primarily driven by higher production costs period-on-period, of which ~40% is explained by non-cash inventory charges, offsetting asmall increase in revenue. l Net cash generated from operating activities (post working capital and tax) in H1 2026 was US$97.2 million (H1 2025: US$53.8 million). l As of 30 June 2026, the Group had hedges covering ~1.0 mmbbls of oil production over the six-months ending 31 December 2026, at an average Dated Brent price of US$72.21/bbl (excluding premiums). Post period end,a further 0.3 mmbbls were hedged for the first quarter of 2027 at US$80.60/bbl. l Net debt3 at 30 June 2026 of US$25.7 million reflected cash balances of US$174.3 million of cash (incl. restrictedcash) and debt of US$200.0 million. Guidance and Outlook l All guidance metrics unchanged from July 2026 trading statement: ¡ Production 16,000-18,000 boepd. ¡ Operating costs of US$260-300 million[4]. ¡ Capital expenditure of US$50-80 million[5]. ¡ 2025-2027 free cash flow (pre-debt servicing) of US$200-240 million[6]. l The Group's recommended FPSO EPCI contractor for the Nam Du/U Minh development has been approved by Petrovietnam. The Group has also submitted to Petrovietnam a recommended EPCI contractor for the NamDu/U Minh field facilities. l The Group continues to progress its plans to reinstate production from the Stag field. A replacement CALM buoy has been secured and is undergoing final due diligence inspection and engineering work. Deployment to thefield is expected during Q1 2027, when minor modifications to the existing mooring system will be executedprior to hook up and restart of production, which is expected during Q2 2027. The Group's businessinterruption insurance cover for the current Stag shut-in runs to May 2027. l At CWLH, resumption of production is still targeted for around the end of Q3 2026 following execution of planned remedial works to repair one of the field's subsea riser's J-tube. 2026 FIRST HALF RESULTS SUMMARY US$'000 except as indicated Six monthsended30 June2026 Six monthsended30 June 2025[7] Twelvemonthsended 31December2025 Total hours without a life-altering event (million) 1.09 0.94 1.95Total lost-time injury rate 0.00 0.00 0.00 Production, barrels of oil equivalent per day (boepd)[8] 15,282 20,368 19,829Oil sales volume, barrels (bbls) 2,365,833 2,398,029 4,230,397 Realized oil price per barrel (US$/bbl)[9] 90.43 77.45 74.42Gas sales, thousand standard cubic feet (mscf) 3,142,045 3,480,579 7,052,210 Realized gas price per mscf (US$/mscf) 5.96 5.59 5.83LPG and condensate sales volume (bbls) 492,517 514,534 1,085,482Realized LPG and condensate price per barrel (US$/bbl) 57.74 49.82 45.89 Revenue[10] 234,049 228,264 408,060 Field operating costs[11] (122,338) (96,567) (212,140) Adjusted OPEX/boe (US$/boe)[12] 37.64 26.25 28.02 Adjusted EBITDAX12 101,590 100,626 152,963(Loss)/Profit after tax (4,811) 37,592 (110,747)(Loss)/Profit per ordinary share: basic and diluted (US$) (0.01) 0.07 (0.20)Operating cash flows before movements in working capital 45,867 95,394 123,637Capital expenditure 34,955 69,381 92,807 Net debt (period end)12 (25,688) (107,706) (89,084)
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Operational and financial summary l Hours worked without a life-altering event totaled 1.1 million (H1 2025: 0.9 million), with hours worked period-on- period increased by 16%. l Zero Tier 1 or Tier 2 process safety events, with a focus on asset integrity program and compliance at the Group's operated assets. l H1 2026 production was 15,282 boepd (H1 2025: 20,368 boepd), primarily reflecting the delay in restarting production at CWLH following the scheduled five-yearly dry dock program, with production expected to resume around the end of Q3 2026. Stag production has been offline since 23 March 2026 due to damage to the field facilities caused by Cyclone Narelle. Production is expected back online in Q2 2027. l Oil sales in H1 2026 of 2.4 mmbbls were in line with the prior period (H1 2025: 2.4 mmbbls) supported by the timing of the CWLH lifting, which resulted in a 0.3 mmbbls overlift, and a reduction of crude inventory. Sales volumes of LPG and condensate from Akatara also remained stable in H1 2026 at 0.5 mmbbls (H1 2025: 0.5 mmbbls). Total gas sales were 10% lower than H1 2025, reflecting a brief period of downtime in April 2026 at Akatara's gas processing facility. l The average realized oil price in H1 2026 was US$90.43/bbl (H1 2025: US$77.45/bbl), a 17% increase period- on-period. This was driven by a higher realized Dated Brent price (H1 2026: US$85.21/bbl vs H1 2025: US$73.81/bbl) as global energy markets were disrupted by the conflict in the Middle East from March 2026 onwards and higher average realized premium (H1 2026: US$5.22/bbl vs H1 2025: US$3.64/bbl). The average realized LPG and condensate price in H1 2026 was US$57.74/bbl (H1 2025: US$49.82/bbl), reflecting pricing benchmarks minus transportation costs. The average realized gas price during the period was US$5.96/mscf (H1 2025: US$5.59/mscf). l Revenue before hedging rose 13% to US$261.1 million (H1 2025: US$231.0 million). Following the inclusion of a US$27.1 million (H1 2025: US$2.7 million) hedging charge, revenue after hedging was US$234.0 million, an increase of 3% (H1 2025: US$228.3 million) year-on-year. l Field operating costs for H1 2026 were US$122.3 million (H1 2025: US$96.6 million). The movement is mainly driven by higher costs at CWLH (dry dock program and subsea dive campaign), Montara (higher logistics, operating and repairs and maintenance costs) and PenMal and Akatara (increased repairs and maintenance activity). Stag was broadly stable with higher repairs and maintenance related to the CALM buoy retrieval offset by lower operating and logistics costs following the suspension of production during the repair period. l Adjusted EBITDAX in H1 2026 was US$101.6 million (H1 2025: US$100.6 million). l H1 2026 loss after tax of US$4.8 million (H1 2025: profit after tax of US$37.6 million). l Operating cash flow before movements in working capital in H1 2026 was US$45.9 million (H1 2025: US$95.4 million). l Capital expenditure in H1 2026 totaled US$35.0 million (H1 2025: US$69.4 million). The main activity in H1 2026 was the PM323 Phase 9 drilling campaign, which was delivered more than 20% below budget. l Net debt of US$25.7 million as of 30 June 2026 (30 June 2025: US$107.7 million) reflecting US$200.0 million[13] senior secured bond issued in March 2026 and total cash and cash equivalents of US$174.3 million at the end of the period. For further information, please contact: Jadestone Energy plc Phil Corbett, Head of Investor Relations +44 (0) 7713 687467 (UK) ir@jadestone-energy.com Stifel Nicolaus Europe Limited (Nomad, Joint Broker) +44 (0) 20 7710 7600 (UK) Callum Stewart Jason Grossman Ashton Clanfield Berenberg (Joint Broker) +44 (0) 20 3207 7800 (UK) Ciaran Walsh Dan Gee-Summons Ryan Mahnke Camarco (Public Relations Advisor) +44 (0) 20 3757 4980 (UK) Billy Clegg jse@camarco.co.uk Georgia Edmonds Poppy Hawkins 2026 Half Year Results webcast
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The Company will host an investor and analyst presentation at 9:00 a.m. (BST) on Thursday, 27 August 2026, including a question-and-answer session, accessible through the link below: Webcast link: https://www.investis-live.com/jadestone-energy Event title: Jadestone Energy plc First-Half 2026 Results Time: 9:00 a.m. (BST) Date: 27 August 2026 To join the presentation by phone, please use the below dial-in details from the United Kingdom or the link for global dial-in details: United Kingdom (Local): +44 20 3936 2999 United Kingdom (Toll-Free): +44 808 189 0158 Global Dial-In Details: https://www.netroadshow.com/events Access Code: 615037 OPERATING SAFELY AND RESPONSIBLY H1 2026 H1 2025 FY2025 Total hours without a life-altering event 1,086,530 936,466 1,951,707 Total lost-time injury rate 0.0 0.0 0.0 The Group continued its excellent safety performance in H1 2026, with zero life-altering events, zero lost-time injuries, no significant impact to the environment and a 50% period-on-period reduction in recordable injuries.There were no losses of primary containment Tier 1 process safety incidents, and no regulatory enforcementdirectives. During the period, work continued to address the Montara General Direction 2043 hull integrity managementfindings. To meet one of the General Direction's requirements, an independent third-party review to verify whetherthe Group's hull integrity management approach aligns with common industry practice, sound integritymanagement principles and reduces risks as low as reasonably practicable was progressed, with the draft reportissued on 3 July 2026. The Group continues to expect that General Direction 2043 will be closed by the end of2026. Four Montara FPSO tanks remain under the 2022 Prohibition Notice, with an expected return to service datein Q4 2026 for all four tanks. There were no high potential incidents arising in H1 2026. In preparation for the projected path of Cyclone Narelle, the Stag facility was shut down on 23 March 2026, the export line flushed, the tanker released and all crewevacuated. The cyclone caused major damage with waves heights estimated at 18 meters in the field. On return toStag, the field's CALM buoy, through which tanker mooring and offloading operations take place, was foundpartially submerged, while several conductor stabilizers were missing and other minor damage was noted. Therewas no loss of containment to the environment. The facility remains offline for repairs to be executed. To improve visibility and help ensure compliance with regulatory, operations excellence, maintenance and integritycommitments, the line-of-sight tool developed in Australia was implemented in Malaysia and will be rolled out tothe Group's Indonesia operations in H2 2026. The line-of-sight tool continues to provide both management andstaff clear visibility to the key areas of HSE, maintenance and integrity, well integrity and production metrics.Implementation of the International Association of Oil and Gas Procedures ("IOGP") Process Safety Fundamentals("PSF") is ongoing. The Group's strategy is centered on the premise that, where possible, future oil and gas demand should be metthrough maximizing reserves and production from existing fields and discoveries, rather than exploring for anddeveloping new sources of supply. This key pillar of the Group's strategy reflects the increasing focus onreinvestment in existing fields, as highlighted in the updated Net Zero Emissions scenario in the World EnergyOutlook 2025 report. Jadestone's core capabilities of mature asset management and gas resource developmentacross the Asia-Pacific region highlight the relevance of the Group's strategy in the energy transition. Preliminary H1 2026 Scope 1 Greenhouse Gas ("GHG") emissions for the Group[14] amounted to 282 kilo tonnes of CO2-e, tracking slightly below plan, due to the Stag shut-in referenced above. The Group has committed to interim net GHG emissions reduction targets from its operated assets of 20% by2026 and 45% by 2030 (from 2021 levels). A key direct action to reduce GHG emissions was the successfulupgrade of the re-injection compressor ("RIC") on the Montara Venture FPSO in May 2026. The upgrade has increased gas reinjection capacity by ~30%, delivering a material reduction of flaring emissions by over 100,000 tonnes of CO2-e per year. Through this successful intervention, the Group is on track to achieve its 2026 interim target without a high reliance on Australian Carbon Credit Units ("ACCUs").
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GOVERNANCE There were no changes to the composition of Jadestone's Board during H1 2026. Dr. Adel Chaouch stepped down as a member of the Board's Remuneration Committee in May 2026. Further, the Board established a Reserves Committee during H1 2026. Joanne Williams was appointed as Chair, with Dr. Adel Chaouch and David Mendelson appointed as Committee members. One key responsibility of the Reserves Committee is oversight of the Group's annual reserves audit, a responsibility previously held by the Audit Committee. There were no other changes to the composition of the Board Committees. In April 2026, Phil Cunningham joined Jadestone Energy as Vietnam Country Manager. In June 2026, Mark Craigwas appointed as the Group's new Chief Operating Officer. He has been employed by the Group for over nineyears, and his prior roles include both Australia and Indonesia Country Manager. In July 2026, Kevin Craig joinedthe Group as Australia Country Manager. The Board continues to recognize the importance of effective corporate governance in supporting the Group'slong-term success and remains committed to maintaining high standards of governance. During the period, theBoard continued to operate in accordance with the Quoted Companies Alliance Corporate Governance Code2023, which was adopted with effect from 1 January 2025. In making its decisions, the Board continued to haveregard to its duties under Section 172 of the Companies Act 2006, promoting the long-term success of theCompany while accounting for the interests of its key stakeholders. OPERATIONAL REVIEW MALAYSIA PM323 PSC (60% working interest, operator) The PM323 PSC produced an average of 2,351 bopd (H1 2025: 2,819 bopd) net to Jadestone's working interest inH1 2026. The period-on-period decrease was primarily due to natural decline, partially offset by the initial impact ofthe East Belumut Phase 9 drilling campaign late in the period. The Phase 9 drilling campaign was originallyplanned as a two firm, one contingent, well program focusing on the undrained southwestern area of the fielddiscovered during the 2023 drilling campaign. The first well in the 2026 campaign, EBA-18ST3, was drilled ~20% below budget. This was an excellent resultconsidering the 1,200-meter horizontal reservoir section in the well at a total measured depth of 4,866 meters, thelongest of any well drilled to date on the East Belumut field prior to the second well in the campaign. The second well in the 2026 campaign, EBA-07ST1, was drilled ~13% below budget with a 930-meter horizontalreservoir section at a total measured depth of 5,473 meters. It was the longest well drilled to date on the EastBelumut field, exceeding the length of the first well in the 2026 campaign by 600 meters. Furthermore, the ERD ratio[15] of the well was 4.1, which is the highest ERD ratio of any well drilled to date in Malaysia, furtherdemonstrating Jadestone's drilling capabilities and ability to add reserves and value to existing fields. The encouraging results of the first two wells in the 2026 drilling program resulted in a decision to drill the thirdcontingent well. The third well, EBA-19ST2, was drilled with an 800-meter horizontal reservoir section in the well ata total measured depth of 5,125 meters. The well was successfully brought onstream at ~2,500 bopd. The Group remains confident that engagement with the regulator to extend the term of the PM323 PSC will besuccessful. A total of 0.3 mmbbls (H1 2025: 0.2 mmbbls) was lifted from the PM323 PSC during H1 2026, with an averagerealization of US$97.53/bbl (H1 2025: US$72.22/bbl). PM329 PSC (100% working interest, operator) PM329 PSC produced an average of 1,237 boepd in H1 2026 (H1 2025: 1,132 boepd) based on Jadestone's100% working interest, which increased from 70% on 1 January 2026 following the exit of the Group's previouspartner in the PSC. This compares with H1 2025 production of 1,132 boepd based on the 70% working interestduring that period. The underlying period-on-period decrease in production was due to natural decline. A total of 0.2 mmbbls (H1 2025: 0.1 mmbbls) of oil was lifted from the PM329 PSC in H1 2026, with an averagerealization of US$101.14/bbl (H1 2025: US$71.08/bbl). In addition, approximately 0.04 bscf (H1 2025: 0.3 bscf) ofgas was sold at an average realization of US$2.85/mscf (H1 2025: US$1.33/mscf). Puteri Cluster (100% working interest, operator) and PM428 PSC (60% working interest, operator) The Group is continuing its technical assessment of the Puteri Cluster PSC ahead of a decision to submit a fielddevelopment and abandonment plan to PETRONAS by the end of 2026. The PM428 PSC is adjacent to the PM323 and PM329 PSCs and surrounds the Puteri Cluster PSC. During theperiod, seismic reprocessing and prospect mapping continued ahead of a drill or drop decision before year-end2026.
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INDONESIA Akatara field, Lemang PSC (100% working interest[16], operator) Akatara production during H1 2026 averaged 5,590 boepd (H1 2025: 5,771 boepd). Total production in H1 2026was evenly split between gas and liquids (LPG and condensate). A total of 3.1 Bscf (H1 2025: 3.2 bscf) of Akatara gas was sold in H1 2026 at a weighted average gas price of US$5.99/mscf (H1 2025: US$5.99/mscf), while 0.5 mmbbls (H1 2025: 0.5 mmbbls) of LPG and condensate were sold at a weighted average price of US$57.74/bbl(H1 2025: US$49.82/bbl), reflecting pricing benchmarks less transportation costs. The HSE performance at Akatara remains impressive, with over 9.5 million manhours having been worked to datein both the development and production phase without a lost-time injury. Asset performance during the first half was in line with expectations, except for a three-week period of unplanneddowntime in April for repairs to the Akatara Gas Processing Facility's ("AGPF") inlet compressors. During theoutage, work originally scheduled to be completed in a planned 7-day shutdown later in 2026 was accelerated andcompleted. Since production resumed in late April 2026, gross field production has averaged ~6,400 boepd with~98% uptime of the AGPF. Following the successful first phase of AGPF debottlenecking in 2025, concept studies, engineering and valueanalysis for the second phase are being undertaken in 2026, ahead of a decision to implement the works in 2027. The Lemang PSC carries a remaining commitment to acquire 403km2 of 3D seismic and drill an exploration well.Jadestone is proposing to convert the seismic commitment into a further well due to the remaining PSC area beinginsufficient to fulfil the seismic acquisition obligation. Existing 2D seismic is currently being reprocessed todetermine potential drilling candidates which, if suitable targets are identified, any drilling is currently expected totake place in 2028. VIETNAM Block 51 (100% working interest, operator) and Block 46/07 (100% working interest, operator) PSCs During the first half of 2026, the Group made significant progress towards the commercialization of the Nam Du/UMinh ("ND/UM") gas discoveries. The FDP was formally approved by the Vietnam Government on 18 March 2026. The GSPA for the supply of gasfrom ND/UM was signed in April 2026. Gross 2P reserves of ~32 mmboe have been booked for the initial phase ofthe project. The ND/UM FDP is based on an unmanned wellhead platform located at both fields, each with two productionwells tied back to a gas processing FPSO. Gas is to be exported through a 34km pipeline tied into an existingtrunkline to the Ca Mau industrial complex onshore. The FDP sets out a phased development, with Nam Dubrought onstream first, accelerating gas to the buyer and revenue to the project partners, which will help fund thedevelopment of U Minh. In June 2026, the Group recommended an EPCI FPSO contractor to the Vietnamese upstream regulator(Petrovietnam), which was approved in August 2026. In late July 2026, the Group recommended an EPCIcontractor for the wellhead platforms and pipeline infrastructure. As part of its development strategy for the ND/UM fields, the Group formally launched a farm-out process in May2026, which attracted strong interest from reputable industry players from across the Asia-Pacific region. TheGroup remains on track to complete the farm-out process and reach a final investment decision on the ND/UMproject by the end of 2026. In advance of commencing its development activity, the Group has made several key hires for its Vietnam projectdelivery team. During the period, Phil Cunningham was appointed as Vietnam Country Manager. With over 30years' experience in the upstream industry, including positions of increasing seniority with some of the world'slargest upstream companies, Phil's background is expected to be ofsignificant benefit to the Group during the development phase. AUSTRALIA CWLH (33.33% working interest, non-operator) During H1 2026, the Group's net production from CWLH fields averaged 1,145 bopd (H1 2025: 3,311 bopd).Production was impacted following the scheduled dry-docking of the Okha FPSO for its five-yearly maintenanceprogram and subsequent delay in reconnecting the FPSO to the field infrastructure. As disclosed previously, the Okha FPSO arrived back on station at the CWLH fields in May 2026 following asuccessful dry dock. However, routine inspections prior to the vessel's return identified an issue with the subseariser's J-tubes. The necessary repairs were subsequently confirmed by the field's operator, Woodside. Detailed repair plans havebeen developed to support a safe return to operations. Regulatory approvals have now been received. With
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execution of the planned works, resumption of production is targeted around the end of Q3 2026. During H1 2026, the Group lifted two (H1 2025: one) CWLH cargoes totaling 0.9 mmbbls (H1 2025: 0.7 mmbbls),with a weighted average realized price of US$80.24/bbl (H1 2025: US$78.86/bbl), comprising Dated Brent ofUS$77.41/bbl and a premium of US$2.83/bbl (H1 2025: Dated Brent of US$79.23/bbl and a discount ofUS$0.37/bbl). MONTARA (100% working interest, operator) During H1 2026, the Group's net production from Montara field averaged 4,195 bopd (H1 2025: 4,229 bopd).Production was broadly in line with expectations during the period. The main activity at Montara in H1 2026 was the planned upgrade of the FPSO's RIC. The RIC upgrade wassuccessfully executed in May 2026 and is expected to reduce annual Montara GHG emissions by 100,000 tonnesper annum, or 45% of 2026 forecasted GHG emissions, and add ~250 bopd to Montara's production potential. The Group continues to work towards satisfying the requirements of the General Directive issued by NationalOffshore Petroleum Safety and Environmental Management Authority ("NOPSEMA") in September 2025. TheGroup has complied with three out of five of the General Direction requirements and there has been significant,and continuing, progress and engagement with NOPSEMA on the remaining two requirements. During the period, the Group continued to evaluate the potential for developing the Montara licenses' gasresources at the end of commercial life of the existing oil development. In total, three cargoes (H1 2025: two) totaling 0.8 mmbbls (H1 2025: 0.9 mmbbls) were lifted from Montara in H12026, with a weighted average realized price of US$97.32/bbl (H1 2025: US$75.14/bbl), comprising an averageDated Brent price of US$91.32/bbl and an average premium of US$6.00/bbl (H1 2025: Dated Brent ofUS$72.83/bbl and an average premium of US$2.31/bbl). STAG (100% working interest, operator) Stag field production averaged 764 bopd in H1 2026, compared to 2,209 bopd in H1 2025. As previously announced, the Stag field was shut-in on 23 March 2026 in advance of the projected path ofCyclone Narelle, which generated estimated wave heights of 18 meters at the field. The Stag field's CALM buoy,through which tanker mooring and offloading operations take place, sustained damage from the storm. Following efforts to refloat the existing CALM buoy, the Group believes that a replacement CALM buoy offers themost efficient, timely and cost-effective way of restoring production at Stag. A replacement CALM buoy has beenidentified and is undergoing final due diligence engineering work. Deployment to the field is expected during Q1 2027, when minor modifications to the existing mooring system willbe executed prior to hook up and restart of production, which is now expected during Q2 2027. The Group'sbusiness interruption insurance cover for the current Stag shut-in runs to May 2027. The Group continues to engage constructively with its insurers through the standard claims process and expectsto receive an initial payment of ~US$12 million in Q3 2026. The Group continues to expect that the Stag shut-inwill not have a material financial impact on current year or longer-term cashflow projections. The Group sold two Stag cargoes totaling 0.3 mmbbls in H1 2026 (H1 2025: two cargoes of 0.5 mmbbls) with aweighted average realized price of US$88.85/bbl (H1 2025: US$83.04/bbl). The first cargo was lifted in February2026 at a realized price of US$76.34/bbl, incorporating a premium of US$5.19/bbl. The second cargo, lifted in April2026, achieved a realized price of US$135.05/bbl, incorporating a premium of US$27.50/bbl. FINANCIAL REVIEW
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The following table provides selected financial information of the Group, which was derived from, and should be read in conjunction with, the unaudited condensed consolidated interim financial statements for the period ended 30 June 2026. US$'000 except as indicated Six monthsended 30June 2026 Six monthsended 30June 2025[17] Twelvemonthsended 31December2025 Production, boepd[18] 15,282 20,368 19,829 Oil sales volume, barrels (bbls) 2,365,833 2,398,029 4,230,397 Realized oil price per barrel (US$/bbl)[19] 90.43 77.45 74.42 Gas sales, thousand standard cubic feet (mscf) 3,142,045 3,480,579 7,052,210 Realized gas price per mscf (US$/mscf) 5.96 5.59 5.83 LPG and condensate sales volume (bbls) 492,517 514,534 1,085,482Realized LPG and condensate price per barrel (US$/bbl) 57.74 49.82 45.89 Revenue[20] 234,049 228,264 408,060 Field operating costs[21] (122,338) (96,567) (212,140) Adjusted OPEX/boe (US$/boe)[22] 37.64 26.25 28.02 Adjusted EBITDAX6 101,590 100,626 152,963Unit depletion, depreciation and amortization (US$/boe) 21.18 14.15 11.82 (Loss)/Profit before tax (7,763) 42,869 (133,673) (Loss)/Profit after tax (4,811) 37,592 (110,747)(Loss)/Profit per ordinary share: basic and diluted (US$) (0.01) 0.07 (0.20)Operating cash flows before movements in workingcapital 45,867 95,394 123,637 Capital expenditure 34,955 69,381 92,807 Net debt (period end)6 (25,688) (107,706) (89,084) Benchmark commodity price and realized price The actual average realized oil price in H1 2026, excluding the effect of hedging, increased by 17% to US$90.43/bbl (H1 2025: US$77.45/bbl) as global energy markets were disrupted by the Middle East conflict leading to a 15% increase in the benchmark realized Dated Brent price for liftings to U$85.21/bbl (H1 2025: US$73.81/bbl) and the average realized premium to US$5.22/bbl (H1 2025: US$3.64/bbl). The average realized gas price in H1 2026 increased to US$5.96/mscf (H1 2025: US$5.59/mscf). Production and liftings Average production in H1 2026 was 15,282 boepd, compared with 20,368 boepd in H1 2025. Production was impacted by the CWLH dry dock program and subsequent reconnection activities, as well as the suspension of production at Stag. Quarterly production averaged 18,266 boepd in Q1 2026 and 12,130 boepd in Q2 2026, predominantly due to CWLH and Stag downtime. · CWLH production decreased by 2,166 bopd to 1,145 bopd (H1 2025: 3,311 bopd) due to the scheduled dry dock of CWLH and subsequent reconnection issue with a resumption of production targeted around the end of Q3 2026. · Stag production decreased by 1,445 bopd to 764 bopd in H1 2026 (H1 2025: 2,209 bopd) as Stag was affected by cyclone damage to its CALM buoy, leading to extended downtime with a restart of production now expected during Q2 2027. · Montara produced 4,195 bopd (H1 2025: 4,229 bopd) in line with expectations and broadly flat with prior period. · PenMal production decreased by 363 boepd to 3,588 boepd in H1 2026 (H1 2025: 3,951 boepd), primarily due to natural decline in the PM329 PSC and the production shutdown associated with the PM323 Phase 9 drilling campaign. This was partially offset by incremental production from new wells brought onstream towards the end period. · Akatara's production decreased by 181 boepd to 5,590 boepd in H1 2026 (H1 2025: 5,771 boepd), mainly due to temporary inlet compressor issues in April 2026. The issue was promptly rectified, enabling operations returning to full production. · The Group disposed of its interest in the Sinphuhorm Assets in April 2025 (H1 2025: 898 boepd). During H1 2026, the Group lifted 2.4 mmbbls (H1 2025: 2.4 mmbbls) of crude oil, 3.1 bscf (H1 2025: 3.5 bscf) of gas and 0.5 mmbbls (H1 2025: 0.5 mmbbls) of LPG and condensate.
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Revenue The Group generated gross revenue before hedging of US$261.1 million in H1 2026, an increase of 13% compared with US$231.0 million in H1 2025. This was partially offset by a higher commodity swap hedge expense of US$27.1 million (H1 2025: US$2.7 million). As a result, net revenue increased to US$234.0 million in H1 2026, compared with US$228.3 million in H1 2025. The increase in revenue by US$30.1 million was explained by: · Higher realized oil (H1 2026: US$90.43/bbl vs H1 2025 US$77.45/bbl) and gas prices (H1 2026: US$5.96/mscf vs H1 2025: US$5.59/mscf) increased revenue by US$31.1 million and US$1.2 million respectively; and · Higher realized LPG (H1 2026: US$54.34/bbl vs H1 2025 US$51.76/bbl) and condensate prices (H1 2026: US$65.23/bbl vs H1 2025: US$45.88/bbl) contributed to a net revenue increase of US$2.7 million. The increase in revenue was offset by: · Lower sales volumes of crude oil and gas by US$2.9 million and US$1.9 million respectively; · Slightly lower production volumes of LPG and condensate; and · Higher hedging expense of US$27.1 million (H1 2025: US$2.7 million) reflecting the higher Dated Brent price in the period. Production costs Production costs increased by US$44.0 million to US$164.0 million (H1 2025: US$120.0 million), comprising field operating costs of US$122.3 million (H1 2025: US$96.6 million), royalties of US$11.6 million (H1 2025: US$11.1 million) and inventory movements of US$30.1 million (H1 2025: US$12.3 million). (i) Field operating costs Field operating costs increased by US$25.7 million to US$122.3 million (H1 2025: US$96.6 million) and include operating costs, workovers, logistics, repairs and maintenance and transportation costs. The increase was mainly driven by: · CWLH field operating costs increased by US$14.0 million to US$30.4 million in H1 2026 (H1 2025: US$16.4 million) which included approximately US$10.0 million of costs associated with the dry dock program, and US$4.0 million increase mainly related to a subsea dive campaign and other costs. · Montara field operating costs increased by US$7.3 million to US$41.5 million in H1 2026 (H1 2025: US$34.2 million) primarily reflecting higher logistics costs associated with increased supply vessel rates, helicopter costs and airport license fees and an increase in operating costs driven by higher labor, chemicals and hull inspection-related activities. · PenMal field operating costs increased by US$2.8 million to US$14.6 million in H1 2026 (H1 2025: US$11.8 million), primarily attributable to higher logistics costs mainly reflecting higher fuel prices. · Akatara field production costs increased by US$1.7 million to US$7.0 million in H1 2026 (H1 2025: US$5.3 million), predominantly due to repairs and maintenance activity during an unplanned shutdown in April 2026. · Stag field operating costs remained broadly stable at US$28.8 million in H1 2026 with a slight decrease of US$0.1 million (H1 2025: US$28.9 million) with higher repairs and maintenance expenditure associated with cyclone-related damage and subsequent remediation activities largely offset by lower operating and logistics costs following the suspension of production during the repair period. (ii) Royalties and inventory movements Royalties and inventory movements increased by US$18.3 million to US$41.7 million (H1 2025: US$23.4 million) comprising increases of US$0.5 million (H1 2026: 11.6 million, H1 2025: US$11.1 million) and US$17.8 million (H1 2026: US$30.1 million, H1 2025: 12.3 million) respectively. Royalties remained broadly stable during the period, increasing by US$0.5 million to US$11.6 million. The inventory movements were primarily driven by a US$21.6 million increase in CWLH, mainly due to the timing of crude liftings between reporting periods. The H1 2026 charge of US$22.6 million reflected the recognition of prior-year underlift inventory from FY2025 into production costs upon lifting during the period, together with the current-period overlift inventory. In contrast, the H1 2025 charge of US$1.0 million comprised the recognition of FY2024 underlift inventory upon lifting, largely offset by a new underlift inventory balance, the related costs of which were deferred and recognized when the crude was subsequently lifted. This was further impacted by a US$1.7 million reduction in the PenMal overlift position.
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Stag crude inventory increased by US$1.2 million, partially offset by a reduction of US$6.6 million in Montara inventory costs. Depletion, depreciation and amortization ("DD&A") Net depletion charges for oil and gas properties increased by US$2.1 million to US$37.2 million in H1 2026 (H1 2025: US$35.1 million). The increase in DD&A expense occurred despite lower production volumes, reflecting changes in the charges of the producing asset base. Production declines were primarily attributable to Stag and CWLH. Stag did not incur any DD&A charge following the impairment recognized in December 2025, while CWLH generated only a minimal DD&A charge due to its low asset carrying value. Although production from these assets declined, the impact on DD&A was not material. The H1 2026 charge was therefore largely driven by production from Montara, Akatara and PenMal. At PenMal, the unit depletion rate increased materially following the Phase 9 drilling campaign, as the new wells brought onstream during the period are being depleted over the shorter remaining life of the license. Depreciation of the Group's right-of-use assets and property, plant and equipment decreased by US$2.0 million to US$5.8 million in H1 2026 (H1 2025: US$7.8 million), mainly reflecting the renewal of helicopter and supply vessel leases over longer contracts terms, which reduced the depreciation expense for the period. Administrative staff costs Administrative staff costs increased by US$2.1 million to US$13.5 million in H1 2026 (H1 2025: US$11.4 million), primarily due to higher non-cash share-based payment charges for key personnel, higher performance bonuses and the recruitment of key management positions, including the appointment of the CEO in June 2025. Other expenses Other expenses increased by US$3.1 million to US$13.3 million in H1 2026 (H1 2025: US$10.2 million) mainly due to an increase in foreign exchange differences of US$2.6 million, with a minor increase in professional fees and higher office costs in Vietnam. Other income Other income decreased by US$2.7 million to US$24.1 million in H1 2026 from US$26.8 million in H12025. H1 2026 comprised US$11.2 million of Stag business interruption insurance proceeds, aUS$9.3 million gain on the acquisition of a 30% working interest in PM329, US$2.8 million of interestincome, US$0.4 million of helicopter rebates and US$0.4 million of other income. The decrease wasmainly attributable to the absence of the US$17.5 million gain on disposal of SPH recognized in H12025, together with lower helicopter rebates of US$0.4 million compared to US$5.3 million and lowerinterest income of US$2.8 million compared to US$3.9 million. Plus, the US$11.2 million insuranceproceeds and US$9.3 million acquisition gain in H1 2026. Finance costs Finance costs increase by US$3.5 million to US$29.6 million in H1 2026 (H1 2025: 26.1 million) predominantly due to: · The accretion for the senior secured bond and RBL facility in H1 2026 of US$12.7 million, which is $2.7 million higher than the RBL facility accretion in H1 2025, due to issuance of the senior secured bond in April 2026. · Interest expense on lease payments increased by US$1.5 million to US$2.2 million (2025: US$0.7 million), mainly due to renewal of Montara leases for helicopter and supply vessels. Taxation The income tax credit in H1 2026 of US$3.0 million (H1 2025: tax expense of US$5.3 million)comprised a current tax credit of US$1.4 million (H1 2025: tax charge of US$8.6 million) and adeferred tax credit of US$1.6 million (H1 2025: US$3.3 million). US$'000 H1 2026 H1 2025 (Loss)/Profit before tax (7,763) 42,869
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Effective tax rate 41% 34% Tax at the effective tax rate (3,183) 14,575 Effect of different tax rates across tax jurisdictions 6,870 (116)Non-deductible expenses 4,561 547 Income not subject to tax (21,877) (13,184)Deferred PRRT/PITA tax charged - 1,871Deferred tax assets not recognized in respect of current year taxes 10,635 5,958 Under/(Over) provision of income tax in prior years 42 (5,184)Under provision of deferred tax in prior years - 810 Income tax (credit)/expense (2,952) 5,277 RECONCILIATION OF CASH US$'000 Six months ended 30June 2026 Six months ended 30 June 2025[23] Cash and cash equivalent at the beginning of the period 60,916 95,226 Revenue 234,049 228,264 Other operating income[24] 474 7,723 Production costs (164,049) (120,029) Administrative staff costs (11,900) (11,033) General and administrative expense (12,707) (9,531)Operating cash flows before movements inworking capital 45,867 95,394 Movements in working capital 52,993 (42,685) Net tax (paid)/refunded (1,706) 1,095 Investing activitiesNet proceeds from the transfer of additionalinterest of PM329 PSC 17,792 -Purchases of intangible exploration assets, oiland gas properties, and plant and equipment[25] (31,619) (77,926)Net proceeds from the sale of SinphuhormAssets - 39,352 Other investing activities 2,823 1,544 Financing activitiesProceeds from the exercise of employee shareoptions 535 -Net proceeds from issuance of senior securedbond 194,859 - Repayment of RBL facility (150,000) (33,252) Payment of costs and interest of RBL facility (9,025) (9,646) Repayment of lease liabilities (8,046) (9,326) Other financing activities (1,077) (734) Total cash and cash equivalents at the endof period 174,312 59,042
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NON-IFRS MEASURES The Group uses certain performance measures that are not specifically defined under International Financial Reporting Standards ("IFRS"), or other generally accepted accounting principles. These non-IFRS measures comprise Adjusted OPEX/boe, adjusted EBITDAX and net debt. The following notes describe why the Group has selected these non-IFRS measures. (i) Adjusted OPEX/boe Adjusted OPEX/boe is a non-IFRS measure used to monitor the Group's operating cost efficiency, as it measures operating costs to extract hydrocarbons from the Group's producing reservoirs on a unit basis. Adjusted OPEX/boe is based on total production cost and incorporates lease payments linked to operational activities, net of any income derived from those right-of-use assets involved in production. The calculation excludes factors such as oil inventories movement, underlift/overlift adjustments, inventory write-downs, workovers, non-recurring repair and maintenance expenses, transportation costs, supplementary payments and royalties, expenses related to non-operating assets and DD&A. These adjustments aim to ensure better comparability between periods. The adjusted production costs are then divided by total produced barrels of oil equivalent for the prevailing period to determine the unit operating cost per barrel of oil equivalent. US$'000 except as indicated Six months ended 30 June 2026 Six months ended 30 June 2025[26] Twelve months ended 31 December 2025 Production costs (reported) 164,049 120,029 232,660 Adjustments Lease payments related to operating activities[27] 8,048 7,863 14,779 Other income[28] (433) (3,139) (4,483) Crude inventories movement[29] (30,094) (12,390) 76 Workover costs[30] (2,135) (2,096) (11,200) Non-recurring operational costs[31] (9,858) - - Non-recurring repairs and maintenance[32] (8,673) (2,596) (6,837) Transportation costs[33] (5,174) (4,100) (6,190) Supplementary payments and royalties[34] (11,617) (11,072) (20,596) Adjusted production costs 104,113 92,499 198,209 Total production (barrels of oil equivalent) [35] 2,765,973 3,524,123 7,075,042 Adjusted OPEX/boe (US$/boe) 37.64 26.25 28.02 (ii) Adjusted EBITDAX Adjusted EBITDAX is a non-IFRS measure which does not have a standardized meaning prescribed by IFRS. This non-IFRS measure is included because management uses the measure to analyze cash generation and financial performance of the Group. Adjusted EBITDAX is defined as profit from continuing activities before income tax, finance costs, interest income, DD&A, other financial gains and non-recurring expenses.
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The calculation of adjusted EBITDAX is as follows: US$'000 Six months ended 30 June 2026 Six months ended 30 June 2025[36] Twelve months ended 31 December 2025 Revenue 234,049 228,264 408,060 Production costs (164,049) (120,029) (232,660) Administrative staff costs (13,513) (11,351) (23,781) Other expenses (13,283) (10,153) (49,669) Allowance for expected credit losses - - (105) Impairment of oil and gas properties - - (126,040) Share of results of associate accounted for using the equity method - 1,849 1,849 Other income, excluding interest income 21,274 22,694 32,504 Other financial gains 3 872 928 Unadjusted EBITDAX 64,481 112,146 11,086 Non-recurring: Net loss/(gain) from oil price and foreign exchange derivatives 27,054 2,702 (2,220) Non-recurring OPEX[37] 18,531 2,596 6,837 Oil and gas properties written off - - 8,664 Inventory written off - 622 - Impairment of oil and gas properties - - 126,040 Abandonment expenses - - 18,524 Net gain on disposal of an associate - (17,518) (17,518) Transfer of additional interest of PM329PSC (9,292) - - Others[38] 816 78 1,550 37,109 (11,520) 141,877 Adjusted EBITDAX 101,590 100,626 152,963 (iii) Net debt Net debt is a non-IFRS measure which does not have a standardized definition prescribed by IFRS. Management uses this measure to analyze the net borrowing position of the Group. US$'000 Six months ended 30 June 2026 Six months ended 30 June 2025 Twelve months ended 31 December 2025 Borrowings (principal sum) (200,000) (166,748) (150,000) Cash and cash equivalents 174,312 59,042 60,916 Net debt (25,688) (107,706) (89,084)
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Net debt is defined as the sum of cash and cash equivalents and restricted cash, less the outstanding principal sum of borrowings. 2026 PRINCIPAL FINANCIAL RISKS AND UNCERTAINTIES The Group applies its risk management framework to oversee principal risks and uncertainties. It faces a range of political, technological, environmental, operational, and financial risks, which are continuously monitored and mitigated to ensure they remain within acceptable levels. This risk matrix provides a structured process for identifying risks that could potentially impact the Group's strategic objectives. The Board regularly reviews these key risks and sets corporate targets aligned with acceptable risk levels. Additionally, the Board conducts a comprehensive review of the risk matrix at least twice annually to assess material risks. As of 30 June 2026, the principal risks and uncertainties faced by the Group remain consistent with those disclosed in the 2025 Annual Report on pages 25 to 29. The risk profile has been updated to reflect the cyclone damage at Stag and the FPSO reconnection issues at CWLH during the period. The operational performance risk referred to on page 27 of the 2025 Annual Report has been updated as follows. Severe weather conditions during H1 2026 adversely affected operational performance and necessitated the temporary shut-in of the Stag asset following storm damage to the field's CALM buoy while remediation and rectification activities are performed.. In addition, CWLH remains temporarily shut-in due to delays in reconnecting the FPSO following the scheduled dry dock program. These events adversely impacted production and operational performance during the year. Although such events are inherently difficult to anticipate and plan for, the Group maintains appropriate insurance arrangements to help mitigate the associated financial exposure and minimize the potential impact on the Group's financial performance. The Group's other mitigation strategies as set out in the 2025 Annual Report remain unchanged and continue to apply. GOING CONCERN The Directors have adopted the going concern basis in preparing these unaudited condensed consolidated interim financial statements, having considered the principal financial risks and uncertainties of the Group. The Directors believe that the Group is well placed to manage its financing and other business risks satisfactorily. The Directors have a reasonable expectation that the Group will have adequate resources to continue in operation for a period of at least 12 months from the date of approval of these unaudited condensed consolidated interim financial statements. They therefore consider it appropriate to adopt the going concern basis of accounting in preparing these financial statements. Details of going concern assessment are disclosed in Note 3. STATEMENT OF DIRECTORS' RESPONSIBILITIES The Directors confirm that to the best of their knowledge: a) the condensed consolidated interim set of financial statements has been prepared in accordance with 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 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 true and fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein).
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By order of the Board, Andrew Fairclough Executive Director Chief Financial Officer 27 August 2026 CAUTIONARY STATEMENT This Interim Management Report ("IMR") has been prepared solely to provide additional information to shareholders to assess the Group's strategies and the potential for those strategies to succeed. The IMR should not be relied on by any other party or for any other purpose. The IMR contains certain forward-looking statements. These statements are made by the directors in good faith based on the information available to them up to the time of their approval of this report, but such statements should be treated with caution due to the inherent uncertainties, including both economic and business risk factors, underlying any such forward-looking information. This IMR is unaudited. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Condensed Consolidated Statement of Profit or Loss andOther Comprehensive Income for the six months ended 30 June 2026 Six monthsended30 June2026 Six monthsended30 June 2025[‡‡‡‡‡‡‡‡‡‡]Adjusted Twelvemonthsended 31December2025 Unaudited Unaudited AuditedNotes US$'000 US$'000 US$'000 Consolidated statement ofprofit or lossRevenue 234,049 228,264 408,060Production costs 5 (164,049) *(120,029) (232,660)Depletion, depreciation andamortization 5 (45,470) (47,265) (99,545)Administrative staff costs 5 (13,513) *(11,351) (23,781)Other expenses 5 (13,283) *(10,153) (49,669)Allowance for expected creditlosses - - (105)Impairment of oil and gasproperties - - (126,040)Share of results of associateaccounted for using theequity method - 1,849 1,849Other income 24,097 *26,785 40,149Finance costs 6 (29,597) *(26,103) (52,859)Other financial gains 3 872 928 (Loss)/Profit before tax (7,763) 42,869 (133,673)
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Income tax credit/(expense) 7 2,952 (5,277) 22,926 (Loss)/Profit for theperiod/year (4,811) 37,592 (110,747) (Loss)/Earnings perordinary shareBasic and diluted (US$) 8 (0.01) 0.07 (0.20) The accompanying notes are an integral part of these condensed interim financial statements. Condensed Consolidated Statement of Profit or Loss andOther Comprehensive Income for the six months ended 30 June 2026(continued) Six monthsended30 June2026 Six monthsended30 June 2025[§§§§§§§§§§]Adjusted Twelvemonthsended 31December2025 Unaudited Unaudited AuditedNotes US$'000 US$'000 US$'000 Consolidated statement ofother comprehensive(loss)/income (Loss)/Profit for the period/year (4,811) 37,592 (110,747) Other comprehensive(loss)/incomeItems that may be reclassifiedsubsequently to profit or loss:(Loss)/Gain on unrealized cashflow hedges 15 (36,720) 14,565 18,866Hedging loss/(gain) reclassifiedto profit or loss 15 27,054 2,702 (2,220) (9,666) 17,267 16,646Tax credit/(expenses) relating tocomponents of othercomprehensive income 15 2,900 (5,180) (4,994) Other comprehensive(loss)/income (6,766) 12,087 11,652 Total comprehensive(loss)/income for theperiod/year (11,577) 49,679 (99,095) The accompanying notes are an integral part of these condensed interim financial statements. Condensed Consolidated Statement of Financial Positionas of 30 June 2026 30 June2026 30 June2025[***********]Adjusted 31December2025 Unaudited Unaudited AuditedNotes US$'000 US$'000 US$'000 Assets Non-current assets Intangible exploration assets 10 93,855 92,172 91,620 Oil and gas properties 11 301,101 455,673 305,566 Plant and equipment 11 10,356 10,400 10,503 Right-of-use assets 11 46,227 10,655 43,349 Other receivables 12 284,566 *283,973 273,615
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Derivative financialinstruments 19 - 1,058 - Deferred tax assets 24,233 44,915 20,606 Cash and cash equivalents 13 - 636 310 Total non-current assets 760,338 899,482 745,569 Current assets Inventories 35,887 29,930 41,951 Trade and other receivables 12 50,628 117,570 67,469 Derivative financialinstruments 19 - 8,591 9,331 Tax recoverable 10,639 7,850 11,142 Cash and cash equivalents 13 174,312 58,406 60,606 Total current assets 271,466 222,347 190,499 Total assets 1,031,804 1,121,829 936,068 Equity and liabilities Equity Capital and reserves Share capital 14 460 457 458 Share premium account 14 53,374 52,176 52,505 Merger reserve 146,270 146,270 146,270 Share-based paymentsreserve 29,989 28,048 28,712 Capital redemption reserve 24 24 24 Hedging reserve 15 (447) 6,754 6,319 Accumulated losses (318,048) *(164,898) (313,237) Total equity (88,378) 68,831 (78,949) The accompanying notes are an integral part of these condensed interim financial statements. Condensed Consolidated Statement of Financial Positionas of 30 June 2026 (continued) 30 June2026Unaudited 30 June2025[†††††††††††]AdjustedUnaudited 31December2025AuditedNotes US$'000 US$'000 US$'000 Liabilities Non-current liabilities Provisions 16 729,499 *679,087 698,298 Borrowings 17 200,027 56,952 40,288 Lease liabilities 34,629 922 33,586 Other payables 18 20,413 17,282 20,703 Deferred tax liabilities 16,280 61,414 18,650 Total non-currentliabilities 1,000,848 815,657 811,525 Current liabilities Provisions 16 7,924 5,549 9,244 Borrowings 17 - 110,605 111,093 Lease liabilities 10,035 10,146 8,351 Trade and other payables 18 97,525 105,441 72,460 Derivative financialinstruments 19 397 - - Warrants liability 20 - 59 3 Tax liabilities 3,453 5,541 2,341 Total current liabilities 119,334 237,341 203,492 Total liabilities 1,120,182 1,052,998 1,015,017 Total equity andliabilities 1,031,804 1,121,829 936,068
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The accompanying notes are an integral part of these condensed interim financial statements. Condensed Consolidated Statement of Changes in Equityfor the six months ended 30 June 2026 Share- Share based Capital Share premium Merger payments redemption Hedging capital account reserve reserve reserve reserve [‡‡‡ US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 As of 1 January2025 457 52,176 146,270 27,730 24 (5,333) Profit for the period - - - - - -Othercomprehensiveincome for theperiod - - - - - 12,087 Profit for theperiod,representing totalcomprehensiveincome for theperiod - - - - - 12,087 Share-basedpayments - - - 318 - - Total transactionswith owners,recognizeddirectly in equity - - - 318 - - As of 30 June2025 457 52,176 146,270 28,048 24 6,754 The accompanying notes are an integral part of these condensed interim financial statements. Condensed Consolidated Statement of Changes in Equityfor the six months ended 30 June 2026 (continued) Share- Share based Capital Share premium Merger payments redemption Hedging
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capital account reserve reserve reserve reserveUS$'000 US$'000 US$'000 US$'000 US$'000 US$'000 As of 1 January 2025 457 52,176 146,270 27,730 24 (5,333) Loss for the year - - - - - -Other comprehensiveincome for the year - - - - - 11,652 Loss for the year,representing totalcomprehensive incomefor the year - - - - - 11,652 Shares issued (Note 14) 1 329 - (330) - -Share-based payments - - - 1,312 - - Total transactions withowners, recognizeddirectly in equity 1 329 - 982 - - As of 31 December 2025 458 52,505 146,270 28,712 24 6,319 The accompanying notes are an integral part of these condensed interim financial statements. Condensed Consolidated Statement of Changes in Equityfor the six months ended 30 June 2026 (continued) Share- Share based Capital Share premium Merger payments redemption Hedgingcapital account reserve reserve reserve reserveUS$'000 US$'000 US$'000 US$'000 US$'000 US$'000 As of 1 January 2026 458 52,505 146,270 28,712 24 6,319 Loss for the period - - - - - -Other comprehensive lossfor the period - - - - - (6,766) Loss for the period,representing totalcomprehensive incomefor the period - - - - - (6,766) Shares issued (Note 14) 2 869 (336)Share-based payments - - - 1,613 - - Total transactions withowners, recognizeddirectly in equity 2 869 - 1,277 - - As of 30 June 2026 460 53,374 146,270 29,989 24 (447) The accompanying notes are an integral part of these condensed interim financial statements.
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Condensed Consolidated Statement of Cash Flowsfor the six months ended 30 June 2026 Six monthsended30 June2026 Six monthsended30 June 2025[§§§§§§§§§§§]Adjusted Twelvemonthsended 31December2025 Unaudited Unaudited Audited Notes US$'000 US$'000 US$'000 Operating activities (Loss)/Profit before tax (7,763) *42,869 (133,673) Adjustments for: Depletion, depreciation andamortization 5 45,470 47,265 99,545 Share-based payments 1,613 318 1,312Allowance for slow-movinginventories - - 1,072 Assets written off - 622 8,664 Allowance for expectedcredit losses - - 105 Impairment of oil and gasproperties - - 126,040 Interest income (2,823) (1,544) (7,645) Insurance income (11,149) - - Gain on change in contingentpayment provision (99) - - Other income (260) - - Reversal of provision - - (3,679) Gain on the sale ofassociate - (17,518) (17,518) Gain on the transfer ofadditional interest ofPM329 PSC 9 (9,292) - - Unrealized foreignexchange gain 576 - (365) Loss/(gain) on hedgeineffectiveness of cash flowhedges 6 62 - (303) Finance costs excluded losson hedge ineffectiveness of cash flowhedges 6 29,535 *26,103 52,859 Other financial gains (3) (872) (928) Share of result of associate - (1,849) (1,849) Operating cash flows beforemovements in workingcapital 45,867 95,394 123,637Working capital movements: Decrease/(increase) in tradeand other receivables 18,034 *(72,504) (29,225) Decrease/(increase) ininventories 3,584 9,669 (1,903) Increase/(decrease) in tradeand other payables 31,375 20,150 (17,888) Cash generated fromoperations 98,860 52,709 74,621 Net tax (paid)/received (1,706) 1,095 8,408 Net cash generated fromoperating activities 97,154 53,804 83,029 The accompanying notes are an integral part of these condensed interim financial statements. Condensed Consolidated Statement of Cash Flowsfor the six months ended 30 June 2026 (continued) Six monthsended30 June Six monthsended30 June Twelvemonths
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2026 2025[************]Adjusted ended 31December2025 Unaudited Unaudited Audited Notes US$'000 US$'000 US$'000 Investing activitiesProceeds from the sale ofSinphuhorm Assets - 39,352 39,359Proceeds from the transfer ofadditional interest of PM329PSC 17,792 - -Payment for oil and gasproperties 11 (29,209) (77,251) (72,413)Payment for plant andequipment 11 (28) (16) (71)Payment for intangibleexploration assets 10 (2,382) (659) (2,133) Interest received 2,823 1,544 7,645 Net cash used in investingactivities (11,004) (37,030) (27,613) Financing activities Proceeds from the exercise ofemployee share options 535 - -Net proceeds from issuance ofsenior secured bond 194,859 - - Repayment of RBL facility (150,000) (33,252) (50,000) Interest on RBL facility paid (8,983) (9,376) (17,737)Commitment fees of RBLfacility paid (42) (270) - Repayment of lease liabilities (8,046) (9,326) (16,206)Other interest and fees paid (1,077) (734) (5,783) Net cash generatedfrom/(used in) financingactivities 27,246 (52,958) (89,726) Net increase/(decrease) incash and cash equivalents 113,396 (36,184) (34,310) Cash and cash equivalents atbeginning of the period/year 60,916 95,226 95,226 Cash and cash equivalentsat end of the period/year 13 174,312 59,042 60,916 The accompanying notes are an integral part of these condensed interim financial statements. Explanation Notes to the Condensed ConsolidatedInterim Financial Statements for the six months ended 30 June 2026 1. General information Jadestone Energy plc (the "Company" or "Jadestone") is an oil and gas company incorporated and registered in England and Wales. The Company's shares are traded on Alternative Investment Market ("AIM") under the symbol "JSE". The Company's registration number is 13152520. The Company is the ultimate parent company of all Jadestone subsidiaries (the "Group"). The financial statements are presented in United States Dollars ("US$") and are rounded to the nearest dollar or nearest US$'000. The Group is engaged in production, development and appraisal activities across Australia, Malaysia, Indonesia and Vietnam.
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The Group's producing assets comprise Montara, Stag and CWLH oil fields, located offshore Western Australia; PM323 and PM329 oil and gas fields, located in shallow water offshore Peninsular Malaysia; and the Akatara gas, LPG and condensate field, located onshore Indonesia. The Group's development assets include the Nam Du and U Minh gas fields, located in Block 46/07 and Block 51 in shallow waters located offshore in southwest Vietnam. The Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower, Singapore 079909. The registered office of the Company is Level 19, The Shard, 32 London Bridge Street, London, SE1 9SG, United Kingdom. 2. New and amended standards New and amended IFRS Accounting Standards that are effective for the current period In the current period, the Group has applied the following amendment to UK-adopted IFRS Accounting Standards which is mandatorily effective for an accounting period that begins on or after 1 January 2026. Its adoption has not had any material impact on the disclosures or on the amounts reported in these financial statements. Amendment Effective date Amendments to IFRS 9 and IFRS 7 - Classification and Measurement of Financial Instruments (including ESG-linked lending features) 1 January 2026 Amendments to IFRS 9 and IAS 7 - Contracts Referencing Nature- dependent Electricity 1 January 2026 Annual Improvements to IFRS Accounting Standards - Volume 11 1 January 2026 New and revised IFRS Accounting Standards in issue but not yet effective At the date of authorization of these financial statements, the Group has not applied the following new and revised IFRS Accounting Standards that have been issued but are not yet effective: Standard Effective date IFRS 18 Presentation and Disclosure in Financial Statements (replaces IAS 1) 1 January 2027 IFRS 19 Subsidiaries without Public Accountability: Disclosures (voluntary) 1 January 2027 The Directors do not expect that the adoption of the standards listed above will have a material impact on the financial statements of the Company in future periods, except as indicated below. IFRS 18 Presentation and Disclosures in Financial Statements ("IFRS 18") IFRS 18 replaces IAS 1 Presentation of Financial Statements ("IAS 1"), carrying forward many of the requirements in IAS 1 unchanged and complementing them with new requirements. In addition, some paragraphs from IAS 1 have been moved to IAS 8 Basis of Preparation of Financial Statements ("IAS 8") and IFRS 7 Financial Instrument: Disclosures ("IFRS 7"). Furthermore, the IASB has made minor amendments to IAS 7 Statements of Cash Flows ("IAS 7") and IAS 33 Earnings per Share ("IAS 33"). IFRS 18 introduces new requirements to: · present specified categories and defined subtotals in the statement of profit or loss; · provide disclosures on management-defined performance measures (MPMs) in the notes to the financial statements; · improve aggregation and disaggregation; and
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· among other requirements. An entity is required to apply IFRS 18 for annual reporting periods beginning on or after 1 January 2027, with earlier application permitted. The amendments to IAS 7 and IAS 33, as well as the revised IAS 8 and IFRS 7, become effective when an entity applies IFRS 18. IFRS 18 requires retrospective application with specific transition provisions. The Directors of the Group anticipate that the application of these amendments will have an impact on the presentation and disclosure of the Company's financial statements in future periods and is currently assessing the detailed impact of these amendments. 3. Material accounting policies Basis of accounting The interim condensed financial statements of Jadestone Energy plc are prepared in accordance with United Kingdom adopted IAS. The condensed set of consolidated financial statements included in this half‑yearly financial report has been prepared in accordance with United Kingdom adopted IAS 34 Interim Financial Reporting. These unaudited condensed consolidated interim financial statements do not comprise statutory accounts within the meaning of Section 435 of the Companies Act 2006 (the "Act"). They do not contain all disclosures required by IFRS for annual financial statements and should be read in conjunction with the Group's audited consolidated financial statements for the year ended 31 December 2025. The information for the year ended 31 December 2025 does not constitute statutory accounts as defined in Section 434 of the Act. A copy of the statutory accounts for that year has been delivered to the Registrar of Companies. The auditors reported on those accounts: their report was unqualified, did not draw attention to any matters by way of emphasis and did not contain a statement under Section 498(2) or (3) of the Act. These financial statements have been prepared on an historical cost basis, except for financial instruments classified as financial instruments at fair value, which are stated at their fair values, and operating leases which are stated at the present value of future cash payments. In addition, these financial statements have been prepared using the accrual basis of accounting. Going concern The Directors have reviewed the Group's forecasts and projections, having considered reasonably possible changes in trading performance and the current macroeconomic environment. Based on this assessment, the Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future, being a period of at least 12 months from the date of approval of these financial statements (the "Review Period"). The assessment included consideration of forecast production levels, associated operating costs, committed capital expenditure and available funding sources. Consideration was also given to the potential impact of commodity price volatility and geopolitical uncertainties affecting global energy markets, which were assessed through various downside price and operational sensitivity scenarios.
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During H1 2026, the Group completed its refinancing program through the issuance of a US$200.0 million senior secured bond, with part of the proceeds being used to fully repay the outstanding US$123.0 million RBL facility with the remaining proceeds retained for corporate purposes. As a result, borrowings previously classified as current liabilities in the Annual Report for 2025 have been refinanced with longer-term funding and are now classified as non-current liabilities, thereby improving the Group's short-term liquidity position. As at 30 June 2026, the Group had available liquidity of approximately US$204.3 million, comprising cash and cash equivalents (including restricted cash) of US$174.3 million, together with additional available liquidity of US$30.0 million from an undrawn working capital facility. As at 31 July 2026, the Group had available liquidity of approximately US$184.9 million, comprising cash and cash equivalents (including restricted cash) of US$154.9 million and the undrawn working capital facility of US$30.0 million. The Group continues to closely monitor its cash flow, funding and liquidity position through regular reviews of both short-term and long-term forecasts, incorporating updated assumptions for production, operating costs, capital expenditure and commodity prices. Sensitivity analyzes have been performed, including scenarios involving lower oil prices and periods of unplanned production downtime. Under these downside scenarios, the Group is expected to maintain sufficient liquidity to meet its operational requirements, committed capital expenditure and debt service obligations throughout the Review Period. Since the balance sheet date, Dated Brent crude oil prices have fluctuated between US$68.79/bbl and US$90.16/bbl, which remains within the Group's operating tolerances. The Group's financial modelling indicates that operations remain viable within this price range. As at 30 June 2026, the Group's total liabilities exceeded its total assets by US$88.4 million (H1 2025: net assets of US$64.0 million). The Group has positive working capital with current assets exceeding current liabilities by US$152.1 million as at 30 June 2026. The majority of the Group's non-current liabilities comprise asset retirement obligations and based on management's current expectations are anticipated to be settled over the next five to ten years. The Directors have also considered the Group's ability to further preserve liquidity through discretionary reductions or deferrals of capital expenditure, optimization of operating costs and other cash management initiatives, should circumstances require it. Having considered the Group's forecast cash flows, available liquidity, successful repayment of the RBL facility and refinancing through the issuance of the new bond, the Directors are satisfied that the Group has adequate resources to continue as a going concern throughout the Review Period. Accordingly, these consolidated financial statements have been prepared on a going concern basis. 4. Critical accounting judgments and key sources of estimation uncertainty In the application of the Group's accounting policies, management is required to make judgments, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other relevant factors. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimate is revised, if the revision
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affects only that period, or in the period of the revision and future periods, if the revision affects both current and future periods. The key judgements and sources of estimation uncertainty remain the same as disclosed in Jadestone's audited consolidated financial statements for the year ended 31 December 2025. 5. Operating costs Six months ended 30 June 2026 Unaudited US$'000 Six months ended 30 June 2025 [††††††††††††]Adjusted Unaudited US$'000 Twelve months ended 31 December 2025 Audited US$'000 Production costs 158,875 *115,929 226,470Tariffs and transportationcosts 5,174 4,100 6,190 Total production costs 164,049 120,029 232,660 Depletion and amortizationof oil and gas properties (Note 11) 37,158 35,082 83,637Depreciation of plantequipment and right-of-use assets (Note11) 5,832 7,802 12,668Crude inventoriesmovement 2,480 4,381 3,240 Total depletion,depreciation and amortization 45,470 47,265 99,545 Staff costs 13,513 *11,351 23,781 Total administrative staffcosts 13,513 11,351 23,781 Corporate costs 13,283 *9,531 21,409Other operating expenses - 622 28,260 Total other expenses 13,283 10,153 49,669 6. Finance costs Six months ended 30 June 2026 Unaudited US$'000 Six months ended 30 June 2025 [‡‡‡‡‡‡‡‡‡‡‡‡]Adjusted Unaudited US$'000 Twelve months ended 31 December 2025 Audited US$'000 Accretion expense on: RBL facility 7,556 9,995 18,928 Senior secured bond 5,168 - - Others 2,488 1,981 4,645 Asset restoration obligations 13,950 *14,127 28,223 Loss on hedgeineffectiveness of 62 - -
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cash flow hedges Other finance costs 373 - 1,063 Total finance costs 29,597 *26,103 52,859 7. Income tax (credit)/expense Six months ended 30 June 2026 Unaudited US$'000 Six months ended 30 June 2025 Unaudited US$'000 Twelve months ended 31 December 2025 Audited US$'000 Corporate tax (credit)/expense Corporate tax (credit)/expense (3,899) 13,811 4,057 Under/(Over) provision in prior years 255 (5,184) (29) (3,644) 8,627 4,028 PITA 2,282 - 206 Over provision in prior years - - (5,772) (1,362) 8,627 (1,538) Six months ended 30 June 2026 Unaudited US$'000 Six months ended 30 June 2025 Unaudited US$'000 Twelve months ended 31 December 2025 Audited US$'000 Deferred corporate tax (credit)/expense Corporate tax credit (6,030) (6,031) (47,471) Under/(Over) provision in prior years 248 810 (13) Tax on hedge ineffectiveness gain of cash flow hedges 73 - 91 (5,709) (5,221) (47,393) PRRT - 1,871 21,817 PITA 4,119 - 1,156 Under provision in prior years - - 3,032 (1,590) (3,350) (21,388) (2,952) 5,277 (22,926) 8. (Loss)/Earnings per ordinary share The calculation of the basic and diluted loss per share is based on the following data: Twelvemonthsended
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Six monthsended30 June Six monthsended30 June 31December 2026 2025 2025Unaudited Unaudited AuditedUS$'000 US$'000 US$'000 (Loss)/Earnings for the purposes ofbasic and diluted per share, beingthe net (loss)/earnings for theperiod/year attributable to equityholders of the Company (4,811) 37,592 (110,747) Six monthsended30 June Six monthsended30 June Twelvemonthsended31December2026 2025 2025Unaudited Unaudited AuditedNumber Number Number Weighted average number ofordinary shares for the purposes ofbasic EPS 594,695,527 541,110,799 541,148,265Effect of dilutive potential ordinaryshares - share options - - -Effect of dilutive potential ordinaryshares - performance shares - 42,096 -Effect of dilutive potential ordinaryshares - restricted shares - 3,998,055 - - 30,000,000 - Weighted average number ofordinary shares for the purposesof diluted EPS 594,695,527 541,110,799 541,148,265 In H1 2026, 18,195,314 of the weighted average potentially dilutive ordinary shares available forexercise from in the money vested options, associated with share options were excluded from thecalculation of diluted EPS, as they are anti-dilutive in view of the loss for the period. In H1 2026, 4,208,720, of weighted average contingently issuable shares associated with the Company's performance share plan based on the respective performance measures up to year- end were excluded from the calculation of diluted EPS, as they are anti-dilutive in view of the loss for the period. In H1 2026, 11,631,119 of weighted average contingently issuable shares under the Company's restricted share plan were excluded from the calculation of diluted EPS, as they are anti-dilutive in view of the loss for the period. In H1 2026, none of weighted average contingently issuable shares under the Company's warrants instruments were excluded from the calculation of diluted EPS, as they are anti-dilutive in view of loss for the period. Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2026 2025 2025 (Loss)/Earnings per share (US$) Unaudited Unaudited Audited - - Basic and diluted[§§§§§§§§§§§§] (0.01) 0.07 (0.20)
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9. Acquisition of additional 30% interest in PM329 PSC On 10 September 2025, the 30% non-operated joint venture partner issued a withdrawal notice in respect of the PM329 PSC, with effect from 1 January 2026. Upon the withdrawal becoming effective, the Group assumed the remaining 30% participating interest in the PM329 PSC and became the sole participant in the license. As part of the transaction, the former joint venture partner paid the Group US$17.8 million in respect of its share of future obligations and other liabilities associated with its withdrawal from the PM329 PSC The transaction has been accounted for as an asset acquisition, as it did not involve the acquisition of a business as defined under IFRS 3. The Group already operated the PM329 PSC and no substantive processes were acquired as part of the transaction. The identifiable assets acquired and liabilities assumed relating to the additional 30% interest in the PM329 PSC were recognized and measured based on their relative fair values at the acquisition date. The allocation of the consideration received is set out below. TotalUS$'000 Assets Non-current asset Other receivables - cess fund 7,462 Current asset Inventories 845 Total assets 8,307 Liability Non-current liability Provision for asset restoration obligations 16,805 Net identifiable liabilities assumed (8,498) Cash receipt from the acquisition *17,790 Net gain on the acquisition 9,292 * For the purpose of the condensed consolidated statement of cash flows, the Group recognized a receivable of US$17.8 million as at the acquisition date. The cash amount was received in March 2026. 10. Intangible exploration assets Total US$'000 Cost As of 1 January 2025 91,323 Additions (a)849 As of 30 June 2025 92,172 Additions (a)1,540Transfer (Note 11) (b)(2,092) As of 31 December 2025 91,620 Additions (a)2,235 As of 30 June 2026 93,855 Net book value As of 30 June 2025 (unaudited) 92,172 As of 31 December 2025 (audited) 91,620
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As of 30 June 2026 (unaudited) 93,855 (a) For the purpose of the condensed consolidated statement of cash flows, current period expenditure on intangible exploration assets of US$0.4 million remained unpaid as of 30 June 2026 (H1 2025: US$0.3 million, FY2025: US$0.6 million). (b) During 2025, the Group transferred US$2.1 million from intangible exploration assets to oil and gas properties as disclosed in Note 11 relating to 3D seismic study performed in 2020 and associated with the Skua-11 side track well drilled in 2025. The amount was subsequently fully impaired in 2025. 11. Oil and gas properties, plant and equipment and right-of-use assets Oil and gas properties Plant andequipment Right-of-useassets Total Productionassets Developmentassets US$'000 US$'000 US$'000 US$'000 US$'000 Cost As of 1January 2025 937,318 - 15,512 44,317 997,147 Additions (a)4,135 (b)64,408 16 2,139 70,698Foreignexchangedifferences (27) - - - (27) As of 30 June 2025 941,426 64,408 15,528 46,456 1,067,818Changes in assetrestorationobligations 9,229 - - - 9,229 Additions (a)22,160 - 55 12,416 34,631Written off (8,664) - - - (8,664)Leasemodification - - - 25,631 25,631Derecognition - - - (4,364) (4,364) Transfer 2,092 - (c)243 - 2,335Foreignexchangedifferences (329) - (7) - (336) Reclassification (b)64,408 (b)(64,408) - - - As of 31 December 2025 1,030,322 - 15,819 80,139 1,126,280 Additions (a)33,225 - 39 8,536 41,800Derecognition - - - (3,472) (3,472)Foreignexchangedifferences (532) - (12) - (544) As of 30 June 2026 1,063,015 - 15,846 85,203 1,161,064
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Oil and gas properties Plant andequipment Right-of-useassets Productionassets Developmentassets TotalUS$'000 US$'000 US$'000 US$'000 US$'000 Accumulateddepletion,depreciation, amortization and impairmentAs of 1 January2025 515,079 - 4,921 28,206 548,206Charge for theperiod 35,082 - 207 7,595 42,884 As of 30 June2025 550,161 - 5,128 35,801 591,090Charge for theperiod(Note 5) 48,555 - 188 4,678 53,421Derecognition - - - (3,689) (3,689)Impairment 126,040 - - - 126,040 As of 31December 2025 724,756 - 5,316 36,790 766,862Charge for theperiod (Note 5) 37,158 - 174 5,658 42,990Derecognition - - - (3,472) (3,472) As of 30 June2026 761,914 - 5,490 38,976 806,380 Net book value As of 30 June2025 (unaudited) 391,265 64,408 10,400 10,655 476,728 As of 31December2025 (audited) 305,566 - 10,503 43,349 359,418 As of 30 June2026 (unaudited) 301,101 - 10,356 46,227 357,684 (a) For the purpose of the condensed consolidated statement of cash flows, current period expenditure on oil and gas properties of US$9.2 million remained unpaid as of 30 June 2026(H1 2025: US$8.5 million, FY2025: US$9.8 million). (b) Development assets relate to the Skua-11 side track well, which commenced drilling in April 2025. The well was completed and brought onstream in August 2025, at which point the capitalized expenditure was transferred to oil and gas properties. (c) The transfer represents the material and spares that are not expected to be consumed within the next 12 months from year end. The reclassification amount is net total of the slow-moving items allowance of US$0.8 million. (d) On 1 January 2026, the Group obtained additional 30% working interest in PM329 PSC. As a result, the Group's working interest in PM329 PSC increased from 70% to 100% as disclosed in Note 9. 12. Trade and other receivables 30 June 2026 30 June 2025 Adjusted 31 December 2025 Unaudited Unaudited Audited US$'000 US$'000 US$'000 [*************]
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Current Trade receivables 18,062 79,027 30,523 Prepayments 4,010 5,184 2,281 Other receivables anddeposits 20,644 11,421 12,099 Amount due from joint arrangement partners 225 2,156 1,807 Underlift crude oilinventories - 11,171 14,410 GST/VAT receivables 8,249 9,024 6,911 Malaysia supplementary payment receivable - 44 - 51,190 118,027 68,031 Allowance for expectedcredit loss (562) (457) (562) 50,628 117,570 67,469 Non-current Other receivables 272,438 [*]270,020 258,525 GST/VAT receivables 12,128 13,953 15,090 284,566 283,973 273,615 335,194 401,543 341,084 Trade receivables originate from revenues earned in Australia, Malaysia, and Indonesia. TheGroup has recognized an allowance for expected credit losses of US$ nil (H1 2025: US$0.5million; FY2025: US$0.5 million) and the remaining outstanding receivables have been recoveredin full. 13. Cash and cash equivalents 30 June 2026 30 June 2025 31 December 2025 Unaudited Unaudited Audited US$'000 US$'000 US$'000 Cash and bank balances,representing cash and cashequivalents in the consolidatedstatement of cash flows, presentedas: Non-current - 636 310 Current 174,312 58,406 60,606 174,312 59,042 60,916 The total current cash & cash equivalents as at 30 June 2026 includes restricted cash balances ofUS$3.9 million (H1 2025: US$4.3 million; FY2025: US$4.3 million). The restricted cash related todeposits placed for bank guarantees in respect of the PenMal assets, the Australian and Indonesiaoffice buildings. As at 30 June 2026, the Group held no cash balances in the RBL Debt Service Reserve Account(H1 2025: US$9.0 million; FY2025: US$2.4 million), following the full repayment and cancellationof the RBL facility on 29 May 2026. 14. Share capital and share premium account Share capital Share premium account
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capital No. of shares US$'000 US$'000 Issued and fully paid As of 1 January/30 June 2025 541,110,799 457 52,176 Issued during the period 1,051,916 1 329 As of 31 December 2025 542,162,715 458 52,505 Issued during the period 2,766,411 2 869 As of 30 June 2026 544,929,126 460 53,374 The Company has one class of ordinary share. Fully paid ordinary shares with par value ofGBP0.001 per share carry one vote per share without restriction and carry a right to dividends asand when declared by the Company. 15. Hedging reserve 30 June 2026 Unaudited US$'000 30 June 2025 Unaudited US$'000 31 December 2025 Audited US$'000 At beginning of the period/year 6,319 (5,333) (5,333) (Loss)/Gain arising on changes in fair value of hedging instruments during the period/year (36,720) 14,565 18,866 Income tax related to loss/(gain) recognized in other comprehensive income 11,016 (4,370) (5,660) Net loss/(gain) reclassified to profit orloss 27,054 2,702 (2,220) Income tax related to amounts reclassified to profit or loss (8,116) (810) 666 At end of the period/year (447) 6,754 6,319 The hedging reserve represents the cumulative gains and losses on hedging instruments deemedeffective in cash flow hedges. The cumulative deferred gain or loss on the hedging instrument isrecognized in profit or loss only when the hedged transaction impacts the profit or loss. 16. Provisions 30 June 2026 30 June 2025[†††††††††††††]Adjusted 31December2025Unaudited Unaudited Audited US$'000 US$'000 US$'000 Non-currentAsset restoration obligations 718,499 [*]668,743 687,938Others 11,000 10,344 10,360 729,499 679,087 698,298 CurrentAsset restoration obligations 3,618 4,109 4,335Others 4,306 1,440 4,909
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7,924 5,549 9,244 737,423 684,636 707,542 17. Borrowings 30 June 2026 Unaudited US$'000 30 June 2025 Unaudited US$'000 31 December 2025 Audited US$'000 Non-current securedborrowings RBL facility - 56,952 40,288 Senior secured bond 200,027 - - Current secured borrowings RBL facility - 110,605 111,093 200,027 167,557 151,381 The Group repaid its US$200.0 million RBL facility in full on 29 May 2026. The outstandingbalance at settlement was US$123.0 million. The Group entered into a US$30.0 million working capital facility on 10 April 2025, with a maturitydate of 31 December 2026. The facility carries a Secured Overnight Financing Rate ("SOFR") plus7% margin and 4% on the undrawn amount. The facility was undrawn as of 30 June 2026. Thefacility, if required, may be drawn upon to support general corporate purposes. On 26 March 2026, the Group successfully completed a US$200.0 million senior secured bondissuance with a maturity in 2031 and a coupon of 12%. The bond principal amortizes at US$50.0million per annum commencing from the third anniversary of the bond issuance, with a finalrepayment of US$100.0 million at maturity. 18. Trade and other payables 30 June 2026 Unaudited US$'000 30 June 2025 Unaudited US$'000 31 December 2025 Audited US$'000 Current Trade payables 13,100 15,043 9,071 Other payables 14,547 15,865 13,229 Accruals 58,704 74,350 47,534 Overlift crude oil inventories 10,047 - - Malaysian supplementary payment payables 635 - 146 Amount due to joint arrangement partner 492 2 2,346 GST/VAT payables - 181 134 97,525 105,441 72,460
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Non-current Other payables 20,413 16,917 20,413 Accruals - 365 290 20,413 17,282 20,703 117,938 122,723 93,163 19. Derivative financial instruments The Group uses derivatives to manage its exposure to oil price fluctuations. Oil hedges are undertaken using swaps. All contracts are referenced to Dated Brent oil prices. During the period, the Group entered commodity swaps that are designated as a cash flow hedge. All hedging undertaken during H1 2026 was deemed effective. 30 June 2026 Unaudited US$'000 30 June 2025 Unaudited US$'000 31 December 2025 Audited US$'000 Derivative financial assets Designated as cash flow hedges Commodity swap - 9,649 9,331 Analyzed as: Current - 8,591 9,331 Non-current - 1,058 - - 9,649 9,331 Derivative financial liabilities Designated as cash flow hedges Commodity swap 397 - - Analyzed as: Current 397 - - The following is a summary of the Group's outstanding derivative contracts as of 30 June 2026: Contractquantity Type ofcontracts Terms Contractprice Hedgeclassification Fair valueliability at30 June2026UnauditedUS$'000 Fair valueasset at30 June2025UnauditedUS$'000 Fair valueasset at31 December2025AuditedUS$'000 Contracts designated as cash flow hedges 20% to70% ofGroup's planned2Pproduction Commodity swap: swap component Jan 2026 - Dec 2026* Weightedaverageprice ofUS$67.89/bbl (H12025:US$70.45 Cash flow (397) 9,649 9,331
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/bbl, 2025:US$69.18/bbl) Subsequent to the period end, a further 0.30 mmbbls were hedged at US$80.60 throughout Q1 2027. 20. Warrants liability On 6 June 2023, in consideration of the support provided to the Company in respect of financing transactions, the Company entered a warrant instrument with Tyrus Capital S.A.M. and funds managed by it, for 30 million ordinary shares at an exercise price of 50 pence sterling per share. The warrants were exercisable within 36 months from the date of issuance and expired on 5 June2026. The Black-Scholes option-pricing model was used to estimate the fair value of warrants. As of 30June 2026, the fair value of warrants liability was US$ nil (H1 2025: US$0.1 million) as comparedto the fair value of warrants as of 31 December 2025 amounting to US$0.03 million. Thedifferences of the fair value of warrants of US$0.03 million were recorded under other financialgains in the condensed consolidated statements of profit and loss and other comprehensiveincome. The Black-Scholes option-pricing model was applied, with the following assumptions, to estimate the fair value of the warrants as at period/year-end: As of30 June 2026 As of30 June 2025 As of 31December2025 Risk-free rate - 3.75% 3.80%Expected life - 0.9 years 0.4 years Expected volatility[51] - 45.93% 40.44% Share price - GBP0.21 GBP0.24Exercise price - GBP0.50 GBP0.50Expected dividends - 0% 0% 21. Segment information Information reported to the Group's Chief Executive Officer (the chief operating decision maker) for thepurposes of resource allocation is focused on two reportable/business segments driven by different types ofactivities within the upstream oil and gas value chain, namely producing assets anddevelopment/exploration assets. The geographic focus of the business is on Australia, Indonesia, Malaysiaand Vietnam. Revenue and non-current assets information based on the geographical location of assets respectively areas follows: Producing assets Exploration/developme AustraliaUS$'000 MalaysiaUS$'000 IndonesiaUS$'000 VietnamUS$'000 CorporatUS$'000 Six months ended 30 June 2026 (unaudited) Revenue Liquids revenue 140,390 46,507 28,438 - Gas revenue - 108 18,606 - 140,390 46,615 47,044 - Production cost (133,202) (19,384) (11,463) - DD&A (29,950) (8,533) (6,808) (42) (13 Administrative staff costs (3,918) (1,662) (637) (651) (6,64 Other expenses (4,487) (3,290) (3,795) (406) (1,30
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Share of results of an associateaccounted for using equity method - - - -Other income 14,149 9,579 135 4 2 Finance costs (12,425) (3,685) 168 (4) (13,65 Other financial gains - - - - (Loss)/Profit before tax (29,443) 19,640 24,644 (1,099) (21,50 Addition to non-current assets 23,438 34,412 (3,272) 1,498 10,0 Non-current assets(a) 170,677 320,293 157,116 87,733 2 Producing assets Exploration/developm AustraliaUS$'000 MalaysiaUS$'000 IndonesiaUS$'000 Thailand(b) US$'000 VietnamUS$'000 Six months ended 30 June 2025 [§§§§§§§§§§§§§]adjusted (unaudited) Revenue Liquids revenue 158,594 24,566 25,632 - - Gas revenue - 393 19,079 - - 158,594 24,959 44,711 - - Production cost (96,222) (14,045) (9,762) - - DD&A (38,073) (1,814) (7,206) - (42) Administrative staff costs (2,549) (1,364) (1,157) - (659) Other expenses (4,299) (1,942) (1,809) (30) (130) Share of results of associate accountedfor using the equity method - - - 1,849 -Other income 8,303 425 371 1 9 Finance costs (10,896) (3,803) (15) - (3) Other financial gains - - - - - Profit/(Loss) before tax 14,858 2,416 25,133 1,820 (825) Additions to non-current assets 78,087 1,133 3,469 (19,544) 815 Non-current assets(a) 296,995 293,924 174,651 - 84,862
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(a) Deferred tax assets are excluded from this segmental information but included in the Group'scondensed consolidated statement of financial position. (b) This represents the income statement amounts for Thailand up until the disposal date of 16 April 2025. Non-current assets in the table comprises intangible exploration assets, oil and gas properties, right-of-useassets, plant and equipment used in corporate offices, investment in associate, other receivables, derivativefinancial instruments and cash and cash equivalents. Deferred tax assets are excluded from the segmentalnote but included in the Group's consolidated statement of financial position. Revenue arising from producing assets relates to the Group's single customer with respect to oilsales in Australia, a different single customer for oil and gas sales in Malaysia, different singlecustomer for gas sales in Indonesia and several customers for LPG and condensate sales inIndonesia. There is an active market for the Group's oil and gas production so they can be sold toother buyers, if required. 22. Events after the end of the reporting period CWLH re-commencement of operations During H1 2026, the CWLH FPSO underwent a planned dry dock as part of its five-year maintenance program. Following the successful completion of the dry dock, technical issues encountered during the reconnection of the FPSO to the field delayed the restart of production until Q3 2026. 23. Prior period adjustments During the audit of the Group's financial statements for the year ended 31 December 2025, several prior period reclassifications and restatements were identified. As these also affect the comparative financial information for the six months ended 30 June 2025, the comparative balances have been adjusted accordingly. (i) Reclassification The reclassification relates to costs associated with the technical onshore office, which have been reclassified from administrative expenses to production costs to better reflect the nature of these costs. This reclassification impacts the presentation of the Group's profit or loss for the six months ended 30 June 2025, as set out below, with no impact on the Group's statement of financial position or cash flows. As the reclassification was reflected in the audited financial statements for the year ended 31 December 2025, there is no impact on the amounts previously reported for that year. The impact of the reclassification on the comparative information is as follows: As previouslyreportedUS$'000 AdjustmentsUS$'000 AsreclassifiedUS$'000 Condensed consolidated statement ofprofit or loss and other
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comprehensive income for the periodended 30 June 2025 Production costs 114,565 5,464 120,029Staff costs 16,738 (5,387) 11,351Other expenses 10,230 (77) 10,153 (ii) Restatements The restatement primarily relates to the timing of recognition of certain income and expenses. The resulting impacts on the Group's profit or loss, assets and liabilities for the six months ended 30 June 2025 are presented in the table below. As the adjustments were reflected in the audited financial statements for the year ended 31 December 2025, there is no impact on the amounts previously reported for FY2025. The impact of the restatements on the comparative information is as follows: As previouslyreportedUS$'000 AdjustmentsUS$'000 As restatedUS$'000 Condensed consolidated statement ofprofit or loss and othercomprehensive income for the periodended 30 June 2025 Other income 24,238 2,547 26,785Finance costs (28,352) 2,249 (26,103) Condensed consolidated statement offinancial position as of 30 June 2025 Other receivables 281,426 2,547 283,973Accumulated losses (169,694) 4,796 (164,898)Provisions 681,336 (2,249) 679,087 Condensed consolidated statement ofcash flows for the six months ended30 June 2025Finance costs excluded loss on hedgeineffectiveness of cash flow hedges 28,352 (2,249) 26,103 Profit before tax 38,073 4,796 42,869Increase in trade and other receivables (69,957) (2,547) (72,504) Glossary 2P the sum of proved and probable reserves, reflecting those reserves with 50%probability of actual quantities recovered being equal or greater to the sum ofestimated proved plus probable reserves AAKBNLP Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields ACCU Australian Carbon Credit Units AGPF/Akatara Akatara Gas Processing Facility AIM Alternative Investment Market ARO Asset restoration obligations bbl/bbls barrel/barrels bopd barrels of oil per day
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bscf billion standard cubic feet the Board the board of directors of Jadestone Energy plc boe barrels of oil equivalent boepd barrels of oil equivalent per day CALM catenary anchor leg mooring CEO Chief Executive Officer CO2-e carbon dioxide equivalent the Company Jadestone Energy plc CWLH Cossack, Wanaea, Lambert and Hermes oil fields offshore Australia Dated Brent the physical benchmark used to price North Sea crude cargoes that have beenassigned a specific loading date DD&A depletion, depreciation and amortization DTR Disclosure Guidance and Transparency Rules EBITDAX earnings before interest tax, depreciation, amortization and explorationexpenditure EPCI engineering, procurement, construction and installation ERD extended-reach drilling EPS earnings per share ESG Environment, Social and Governance FDP field development plan FPSO floating production storage and offloading FY financial year from 1 January to 31 December GBP British pound sterling GHG greenhouse gas the Group Jadestone Energy plc and its subsidiaries GSPA gas sales and purchase agreement H1 Six months period from 1 January to 30 June HSE Health, Safety and Environment IAS International Accounting Standards IASB International Accounting Standards Boards IFRS International Financial Reporting Standards IOGP International Association of Oil and Gas Procedures IMR Interim Management Report JSE Jadestone Energy plc km kilometer LPG Liquefied petroleum gas mm million mmbbls million barrels mmboe million barrels of oil equivalent mscf thousand standard cubic feet of natural gas ND/UM Nam Du and U Minh gas fields offshore Vietnam NOPSEMA National Offshore Petroleum Safety and Environmental Management Authority OPEX operating expenditure PenMalAssets collectively, Jadestone's Peninsular Malaysia assets PETRONAS Petroliam Nasional Berhad PITA Petroleum Income Tax PNLP Assets collectively, several oil fields offshore Peninsular Malaysia in which Jadestoneacquired a non-operated interest as part of its wider Peninsular Malaysia entryin 2021. These assets, originally known as the PM318/AAKBNLP PSCs, wererenamed the PNLP Assets after Jadestone assumed operatorship of thelicenses in April 2023 following the withdrawal of the previous operator. Certainof the PNLP Assets were included in the Malaysia Bid Round Plus, withJadestone subsequently being awarded a 100% interest in the Puteri Cluster in2024. PRRT Petroleum Resource Rent Tax PSC production sharing contract PSF Process Safety Fundamentals RBL Reserve-based lending RBL Facility the Group's US$200 million reserve-based lending facility obtained in May 2023with a four-year tenor reserves hydrocarbon resource that is anticipated to be commercially recovered fromknown accumulations from a given date forward RIC re-injection compressor SinphuhormAssets the Group's former indirect interest in the Sinphuhorm gas field in Thailand,which was disposed of in April 2025 SOFR Secured Overnight Financing Rate US$ United States Dollar UK United Kingdom
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The technical information contained in this announcement has been prepared in accordance with theJune 2018 guidelines endorsed by the Society of Petroleum Engineers, World Petroleum Congress,American Association of Petroleum Geologists and Society of Petroleum Evaluation EngineersPetroleum Resource Management System. A. Shahbaz Sikandar of Jadestone Energy plc, Group Subsurface Manager with a Master's Degreein Petroleum Engineering and a member of the Society of Petroleum Evaluation Engineers with over30 years' experience in the energy industry, has read and approved the technical disclosure in thisregulatory announcement. The information contained within this announcement is considered to be inside informationprior to its release, as defined in Article 7 of the Market Abuse Regulation No. 596/2014 whichis part of UK law by virtue of the European Union (Withdrawal) Act 2018, and is disclosed inaccordance with the Company's obligations under Article 17 of those Regulations. [1] Indonesia, Malaysia and Australia [2] The extended-reach drilling ("ERD") ratio represents the horizontal distance (unwrapped displacement) of a well from the surface location divided by the vertical depth of the well and measures the reach of a well from a single surface location. [3] Adjusted unit operating costs per boe ("Adjusted OPEX/boe"), adjusted EBITDAX and net debt are non-IFRS measures and are explained in further detail on the non-IFRS measures section in this document. [4] Movements in FX rates, primarily the Australian dollar vs. the US dollar, and the impact of higher oil prices on royalties and diesel costs is now likely to mean an outcome in the upper half of the range. The 2026 guidance range excludes ~US$6 million of operating costs associated with the Stag CALM buoy recovery operation and disposal, which is expected to be offset by insurance proceeds. [5] Consistent with previous disclosures, the guidance range reflects expenditure on the Group's existing producing assets, with only a small amount budgeted for pre- sanction costs in Vietnam. The guidance range excludes ~US$11 million of capital expenditure associated with the Stag CALM buoy recovery and replacement operations, which is expected to be fully offset by insurance proceeds. [6] Based on a Dated Brent oil price of US$70/bbl (real terms from 2025). Does not reflect any capital expenditure or abandonment spend outside the Group's producing assets. [7] Certain H1 2025 comparative information has been reclassified. A total of US$5.5 million was reclassified to field operating costs, comprising US$5.4 million from administrative staff costs and US$0.1 million from other expenses to operating costs, to better reflect the nature of technical office costs. Accordingly, H1 2025 adjusted OPEX/boe has been updated to reflect the revised production figures and no changes noted for adjusted EBITDAX. [8] H1 2025 production includes Sinphuhorm Assets gas production up to the point of divestment in accordance with Petroleum Resource Management Systems guidelines, non-IFRS measures. However, in accordance with IAS 28 the investment is accounted for as an associated undertaking and only recognizes the share of results of associate. Accordingly, the revenue and production costs from the Sinphuhorm Assets are excluded from the Group's financial results. Not applicable for H1 2026. [9] Realized oil price represents the actual selling price inclusive of premiums, excluding the effect of hedging. [10] Revenue in H1 2026 and H1 2025 include hedging losses of US$27.1 million and US$2.7 million respectively. [11] Field operating costs represent production costs less inventory movements and royalties. [12] Adjusted OPEX/boe, adjusted EBITDAX and net debt are non-IFRS measures and are explained in further detail on the non-IFRS measures section in this document. [13]In May 2026, the Group successfully refinanced its debt through the issuance of a US$200.0 million senior secured bond. Part of the bond proceeds were used to fully redeem the outstanding RBL facility. [14] Includes 100% of GHG emissions from Montara, Stag, PenMal sites and Akatara Gas field. [15] ERD ratio represents the horizontal distance of a well from the surface location divided by the vertical depth of the well and measures the reach of a well from a single surface location. [16] The local government in Jambi province has an option to take a 10% participating interest in the Lemang PSC, which, if exercised, would reduce Jadestone's working interest to 90%. During the period, Jadestone continued to engage with the Jambi local government over the 10% participating interest. [17] A total of US$5.5 million was reclassified to field operating costs, comprising US$5.4 million from administrative staff costs and US$0.1 million from other expenses to operating costs, to better reflect the nature of technical office costs. Accordingly, H1 2025 adjusted OPEX/boe has been updated to reflect the revised production figures and no changes noted for adjusted EBITDAX.
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[18] Production in H1 2025 includes the Sinphuhorm Assets gas production to the date of divestment in accordance with Petroleum Resource Management Systems guidelines, non-IFRS measures. However, in accordance with IAS 28 the investment is accounted for as an associated undertaking and only recognizes dividends received. Accordingly, the revenue and production costs from the Sinphuhorm Assets are excluded from the Group's financial results. Not applicable for H1 2026. [19] Realized oil price represents the actual selling price inclusive of premiums or discounts and excludes the impact of hedging. [20] Revenue in H1 2026 and H1 2025 include hedging losses of US$27.1 million and US$2.7 million respectively. [21] Field operating costs represent production costs less inventory movements and royalties. [22] Adjusted OPEX/boe, adjusted EBITDAX and net debt/cash are non-IFRS measures and are explained in further detail in the Non-IFRS Measures section of this document. [23] During the 2025 year-end audit process, certain financial information was reclassified and restated. Accordingly, the H1 2025 comparative figures have been adjusted to reflect these changes: (i) a US$2.5 million increase in other income to recognize the full six months of abandonment trust income, (ii) US$5.5 million reclassified to production costs, comprising US$5.4 million from administrative staff costs and US$0.1 million from other expenses, to better reflect the nature of technical office costs, and (iii) a US$2.3 million reduction in finance costs to correct the double booking of accretion costs. There is no impact on FY2025 year-end figures in respect of the restatements. [24] Other operating income, administrative staff costs and general and administrative expenses adjusted figures are non-IFRS measures. [25] Total capital expenditure was US$35.0 million (H1 2025: US$69.4 million), comprising total capital expenditure paid of US$25.8 million (H1 2025: US$60.8 million) and accrued capital expenditure of US$9.2 million (H1 2025: US$8.6 million). [26] Certain H1 2025 comparative information has been reclassified. A total of US$5.5 million was reclassified to production costs, comprising US$5.4 million from administrative staff costs and US$0.1 million from other expenses to operating costs, to better reflect the nature of technical office costs. Accordingly, H1 2025 adjusted unit operating costs per barrel of oil equivalent has been updated to reflect the revised production figures. [27] Lease payments related to operating activities are lease payments considered to be operating costs in nature, including leased helicopters for transporting offshore crews. These lease payments are added back to reflect the true cost of production. [28] Other income represents the rental income from a helicopter rental contract (a right-of-use asset) to a third party. [29] Crude inventories movement are added back to the calculation to match the full cost of production with the associated production volumes (i.e., numerator to match denominator). [30] Workover costs are excluded to enhance comparability. The frequency of workovers can vary across periods. [31] Non-recurring operational costs incurred in H1 2026 significantly relate to the CWLH Asset due to the dry dock expenses. No comparable costs were incurred in H1 2025. [32] Non-recurring repairs and maintenance costs in H1 2026 predominantly relates to CALM buoy rectification and maintenance of pigging of export flowline at Stag and tank maintenance at Montara. Similar costs were incurred in H1 2025, predominantly related to tank maintenance at Montara, and CALM buoy coating remediation and maintenance pigging of export flowline at Stag. [33] Transportation costs include the pipeline tariff at the PenMal Assets and tanker costs at Stag and Montara associated with lifting costs. [34] PenMal Assets supplementary payments are required under the terms of PSCs based on Jadestone's oil profit after entitlements between the government and joint venture partners. The Australian royalties include a temporary levy passed by the Australian Government on offshore petroleum production and a levy on the wellhead value of primary production license from the CWLH Assets. Indonesia royalties are payable to the government of Indonesia based on the volume of natural oil and/or gas produced and sold based on predetermined percentages under the relevant production sharing contract agreement. [35] Gas production (applicable only for H1 2025 and YE 2025) from the Sinphuhorm Assets before the disposal on 16 April 2025 was excluded, as revenue and production costs were not recognized in the Group's financial results following its classification as an investment in an associate. In accordance with IAS 28, the Group recognizes only its share of results of associate. [36] Certain H1 2025 comparative information has been reclassified. A total of US$5.5 million was reclassified to production costs, comprising US$5.4 million from administrative staff costs and US$0.1 million from other expenses to operating costs, to better reflect the nature of technical office costs. These changes did not impact adjusted EBITDAX during the relevant periods. [37] Non-recurring OPEX in H1 2026 mainly represent one-off repair and maintenance costs predominantly related to Montara tank maintenance and CALM buoy coating remediation, maintenance pigging of export flowline at Stag and CWLH Asset dry dock expenses.
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[38] Includes business development related expenses, external funding sourcing costs and refinancing. [‡‡‡‡‡‡‡‡‡‡] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [§§§§§§§§§§] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [***********] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [†††††††††††] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [‡‡‡‡‡‡‡‡‡‡‡] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [§§§§§§§§§§§] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [************] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [††††††††††††] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [‡‡‡‡‡‡‡‡‡‡‡‡] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [§§§§§§§§§§§§] Diluted loss per ordinary share is the same as basic loss per ordinary share as the inclusion of potentially dilutive ordinary shares would be anti-dilutive. [*************] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [†††††††††††††] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. [51] Expected volatility was determined by calculating the average historical volatility of the daily share price returns over a period commensurate with the expected life of the awards for a group of ten peer companies. [§§§§§§§§§§§§§] The adjusted comparative amounts reflect the effects of certain prior period restatements and reclassifications. Please refer to Note 23 for further details. This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authorityto act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this informationmay apply. For further information, please contact rns@lseg.com or visit www.rns.com. RNS may use your IP address to confirm compliance with the terms and conditions, to analyse how you engage with the informationcontained in this communication, and to share such analysis on an anonymised basis with others as part of our commercial services. Forfurther information about how RNS and the London Stock Exchange use the personal data you provide us, please see our Privacy Policy. END