2025 Full-Year Results

2025 Full-Year Results

19 May 2026 - Singapore: Jadestone Energy PLC (AIM:JSE) ("Jadestone" or the "Company"), an independent upstream company and its subsidiaries (the "Group"), focused on the Asia-Pacific region, reports its consolidated audited financial statements (the "Financial Statements"), as at and for the financial year ended 31 December 2025. 

The Company will host 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, commented:

"Jadestone's improved operational performance and cash flow generation in 2025 reflect the organization's hard work and relentless focus on the operational excellence and cost discipline principles which have been instilled under the leadership of our refreshed management team. These results were also underpinned by another excellent year of HSE performance across the Group. However, our financial results were impacted by the previously disclosed impairment, which was the main driver of a loss after tax for the year. Protecting the base business will remain a key focus for the Group, as we work to return to sustainable profits and maximize cash generation to support our future growth ambitions.

The strong momentum from 2025 continued into early 2026, where we have already delivered on several of our key near-term priorities for the year. In Vietnam, we achieved FDP approval and signature of the GSPA for the Nam Du/U Minh project, clearing the key regulatory and commercial milestones required for project execution. The farm-out process has now commenced, and we have been encouraged by both the number and quality of interested parties to date. Separately, we have refinanced our debt with the issuance of our debut bond, removing near-term debt repayments and allowing us to focus near-term cashflow on accretive growth opportunities.

After excellent operating performance in the first quarter of 2026, where we delivered on plan against all key metrics, the second quarter has started with some operational headwinds, primarily associated with the effects of Cyclone Narelle, one of the strongest storms to pass through offshore Western Australia in recorded history. The full impact of the storm is still being assessed, but will likely result in the Stag field remaining offline until the fourth quarter of this year based on current information.

The Okha FPSO has arrived back on station at the CWLH fields following its successful dry-dock. However, recent subsea inspections have established that some minor structural repairs may be required to one of the field's subsea riser's J tube before re-connecting the vessel to the Riser Turret Mooring.

Recent events in the Middle East continue to highlight the strategic value of a diversified portfolio of upstream assets in the Asia-Pacific region - reinforcing our long-standing corporate strategy. We remain geared towards Brent oil price strength, seeing realized prices for our oil sales increase significantly in recent months, with a positive impact on our financial performance. Combined with the bond issue, our financial position has strengthened significantly since the beginning of the year."

2025 - a year of record production, safe operations and portfolio value creation

l Over 12 million manhours worked without a lost-time injury ("LTI") across the Group.

l Delivered record annual production of 19,829 boe/d in 2025 (+6% year-on-year).

l Successful drilling of the Skua-11ST well at Montara in Australia, which extended field life by one year and reduced Montara unit operating costs.

l Sale of the Group's interest in the Sinphuhorm field onshore Thailand for US$39.4 million and contingent payments, representing a 44% return on the Group's ownership and in line with the independently assessed 2P NPV10 of the asset at year-end 2024.

l Independently audited 2P reserves by Sproule ERCE of 56.2 MMboe at year-end 2025 (year-end 2024: 68.3 MMboe), with the reduction from the prior year primarily due to 7.0 MMboe of production in 2025, the sale of the Group's Sinphuhorm interest and the remainder due to technical and economic revisions. In March 2026, significant 2P reserves were booked in relation to the Group's Vietnam assets (see below).

l Year-end 2025 2C resources of 121.7 MMboe (year-end 2024: 125.7 MMboe) reflecting the sale of the Sinphuhorm asset and prior to the Vietnam reserves booking in March 2026.

Higher liftings and lower costs drive significant cashflow generation

l 2025 revenues increased by 3% year-on-year to US$408.1 million (2024: US$395.0 million).

l 2025 production costs decreased by 19% year-on-year to US$232.7 million (2024: US$286.9 million[1]), primarily due to lower field operating costs, workovers, repairs and maintenance activity and reduced lifting and inventory charges.

¡  On an adjusted basis, unit operating costs declined 21% year-on-year to US$28.02/boe (2024: US$35.28/boe)

l 2025 adjusted EBITDAX of US$153.0 million, a 20% increase year-on-year, driven primarily by higher revenues and lower production costs.

l 2025 loss after tax for the period of US$110.7 million (2024: US$44.1 million loss after tax), driven by a post-tax impairment of US$88.2 million, in line with the figure disclosed on 26 February 2026.

l 2025 operating cash flow pre working capital of US$123.6 million, a 75% increase year-on-year (2024: US$70.5 million)

l Net debt at 31 December 2025 was US$89.1 million, a 15% reduction year-on-year (31 December 2024: US$104.8 million). The net debt figure at 31 December 2025 excluded US$23.7 million of proceeds related to liftings in December 2025 received in early 2026.

Current trading and outlook - strengthened financial platform with growing momentum in Vietnam

l In March 2026, the Group successfully placed a Nordic bond issue of US$200 million with a 2031 maturity and a 12% coupon. The bond placement was materially oversubscribed and saw strong investor demand across Nordic and international markets. The net proceeds from the bond issue will be used to repay the Group's outstanding US$122.0 million balance on its reserves-based lending facility (the "RBL Facility"), with the remainder used for general corporate purposes.

l In March 2026, Jadestone received Vietnam government approval for the Nam Du/U Minh field development plan, allowing the Group to book initial 2P reserves for the project of approximately 32 MMboe. In April 2026, the gas sales and purchase agreement for the supply of gas from Nam Du/U Minh was signed. Jadestone's near-term priorities are to conclude the bid evaluation for the FPSO and field infrastructure, and award their respective contracts, during the second half of 2026. A formal farm-out process has been launched to seek partner(s) for the project.

l The PM323 East Belumut infill drilling campaign commenced in April 2026. The two firm plus one contingent well program is designed to follow up on the very successful 2023 infill drilling campaign by targeting the previously undeveloped southwest extension of the East Belumut field. The results of the first well are due in late Q2 2026.

l 2026 production to the end of April has averaged ~16,300 boe/d, primarily reflecting planned downtime at CWLH for the five-yearly class certification and maintenance dry dock of the Okha FPSO and unplanned downtime at Stag from the Cyclone Narelle impact. The Okha FPSO has arrived back on station at the CWLH fields following its successful dry-dock. However, recent subsea inspections have established that some minor structural repairs may be required to one of the field's subsea riser's J tube before re-connecting the vessel to the Riser Turret Mooring. Dependent on the ongoing analysis of the inspection findings, production could be restarted as early as end-May, or if repairs are required, these are expected to be executed within 5-8 weeks.

l The Stag field remains shut in due to the impact of Cyclone Narelle. The main storm damage was to the field's CALM buoy, through which shuttle tankers offload crude produced from Stag. Efforts are underway to ready the CALM buoy for tow to shore, where a full damage assessment will be undertaken to inform next steps, with current expectations of a return to production in the fourth quarter of 2026. The Group has appropriate insurance in place, for both physical damage and business interruption, and is working with insurers through the standard claims process.

l Net debt at 30 April 2026 was approximately US$5 million, consisting of US$117.4 million in cash (incl. restricted cash) and US$122 million of outstanding debt on the RBL Facility. The Group's US$30 million Working Capital Facility remains undrawn.

l The Group's has hedged approximately 1.5 MMbbls for the period April to December 2026 at a weighted average price of US$70/bbl Brent (not including any asset specific premiums or discounts).

Guidance - remains unchanged

l The Group's production guidance of 18,000 - 21,000 boe/d, is unchanged pending further clarity on the restoration of production from the Stag, although an outcome in the lower half of the range is currently considered most likely.

l Total production costs[2] (unchanged): US$260-300 million, with an outcome in the lower half of the range currently considered most likely due to operating cost reductions at Stag during the shut-in period.

l Capital expenditure guidance (unchanged): US$50-80 million. Consistent with earlier 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.

l Based on information currently available, Jadestone does not expect the Stag shut-in to have a material financial impact on the Group's current year or longer-term cashflow projections.

l 2025-27 unlevered free cash flow guidance[3] (unchanged): US$200-240 million at US$70/bbl Brent. Every US$10/bbl move in the underlying Brent assumption is estimated to change the 2025-2027 free cash flow guidance by ±US$90 million.

-ends-

Enquiries

Full-year 2025 presentation webcast

The Company will host an investor and analyst presentation at 9:00 a.m. (UK time) on Tuesday, 19 May 2026, including a question-and-answer session, accessible through the link below:

Webcast link: https://www.investis-live.com/jadestone-energy/69ef1e25fed46a000ff0608b/klaty

Event title: Jadestone Energy Full-Year 2025 Results

Time: 9:00 a.m. (UK time)

Date: 19 May 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/global-numbers?confId=102519

Access Code: 205105

2025 SUMMARY

Certain 2024 comparative information has been reclassified. A total of US$9.9 million was reclassified to production costs, comprising US$9.8 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, 2024 adjusted unit operating costs per barrel of oil equivalent has been updated to reflect the revised production figures.

Operational and financial summary

l Proven and probable ("2P") reserves at 31 December 2025 totalled 56.2 MMboe, a decrease of 12.1 MMboe on end-2024, primarily due to 7.0 MMboe of production in 2025, the sale of the Group's Sinphuhorm interest during the year and the remainder due to technical and economic revisions across the Group.

l Production increased by 6% year-on-year to an annual record of 19,829 boe/d (2024: 18,696 boe/d), primarily due to a full year of production from Akatara, partially offset by the sale of Sinphuhorm and natural declines and downtime at the Group's Australian and Peninsular Malaysia Assets ("PenMal Assets")

¡ On an underlying basis (excluding the Sinphuhorm interest), production increased by 14% during the year.

l Total sales volumes of oil, gas, LPG and condensate increased by 23% in 2025 to 6.5 MMboe (2024: 5.3 MMboe), reflecting the increase in full year production and lifting schedules.

l Revenue increased by 3% to US$408.1 million (2024: US$395.0 million) due to a full year increase in Akatara revenue of US$75.4 million and a US$29.6 million net year-on-year change in hedging offset by a US$92.0 million year-on-year decline in oil sales across Montara, Stag, CWLH, and PenMal, reflecting both lower production levels and reduced realized prices.

l The average realized oil price before hedging decreased 13% to US$74.42/bbl in 2025 (2024: US$85.21/bbl), primarily reflecting movements in underlying benchmark oil prices. The average realized price premium for 2025 was US$3.17/bbl (2024: US$3.76/bbl).

l Production costs of US$232.7 million were 19% lower year-on-year (2024: US$286.9 million). A full-year of Akatara production added US$9.3 million, which was offset by reductions at Montara (US$1.8 million) due to lower operating cost and R&M activity, the PenMal Assets (US$20.9 million) due to lower Puteri Cluster costs, inventory movements, R&M and logistics, CWLH (US$20.7 million) due to purchase price accounting effects in 2024, and Stag (US$20.1 million) due to lower R&M and workovers.

¡ Adjusted unit operating costs decreased by 21% in 2025 to US$28.02/boe (2024: US$35.28/boe), driven by a higher weighting of lower‑cost Akatara production in the portfolio.

l Adjusted EBITDAX for 2025 increased by 20% to US$153.0 million, up from US$127.9 million in 2024, driven by the factors set out above.

l As at 31 December 2025, pre-tax impairment of oil and gas properties amounted to US$126.0 million in 2025 (2024: US$Nil). The after‑tax impact of this impairment was US$88.2 million in 2025 (2024: US$Nil), comprising US$45.3 million in respect of Stag and US$42.9 million relating to Montara.

l 2025 loss after tax of US$105.5 million (2024: US$44.1 million loss after tax), driven by the non-cash impairment.

l 2025 operating cash flow before movements in working capital of US$123.6 million, an increase of 75% compared to 2024 (US$70.5 million).

l 2025 capital expenditure of US$92.8 million increased 25% year-on-year (2024: US$74.5 million), primarily due to the drilling of Skua-11ST well at Montara.

l Net debt of US$89.1 million at 2025 year-end (2024 year-end: US$104.8 million), reflecting US$150.0 million drawn under the RBL Facility[11] and total cash and cash equivalents (including restricted cash) of US$60.9 million.

OPERATING SAFELY AND RESPONSIBLY

The Group continued its strong safety performance in 2025, the Group reported zero life altering events, zero lost time injuries, no significant impacts to the environment and a 61% year-on-year reduction in recordable injuries. During the year the organization received two enforcement directives in Australia and there were two losses of primary containment Tier 1 process safety incidents, neither of which resulted in injury, environmental harm or property damage. The reduction in manhours was a result of the Akatara construction and commissioning coming to an end in 2024.

During 2025, the Group focused on several Health, Safety, and Environment ("HSE") initiatives, including the introduction of the International Association of Oil and Gas Procedures ("IOGP") Process Safety Fundamentals ("PSF"). The ten IOGP PSF rules were developed from decades of experience across the global oil and gas industry and focus on areas where small lapses can lead to major accident events. Other key activities during the period included updating the Group HSE Policy, which now formally incorporates security matters and has been renamed as the Health, Safety, Security and Environment ("HSSE") Policy and ongoing risk management across the Group's operations.

In August a Prohibition Notice was issued in connection with corroded N2 cylinders on the Montara FPSO, which are part of the firefighting foam system. Jadestone proactively shut down production at Montara and replaced eight cylinders, restarting the facility four days later. There was no loss of containment or injury associated with this Prohibition notice.

In September 2025, NOPSEMA issued a General Direction requiring Jadestone to revise its policies and approach to the hull integrity management of the Montara Venture FPSO, and commission an independent review and verification that the Group's hull integrity management approach aligns with common industry practice and sound integrity management principles. Four tanks remain under the 2022 Prohibition Notice, with expected an return to service date in the fourth quarter of 2026 for all four tanks. The Level 4 regulatory investigation into the 2022 Montara 2 Centre Crude Oil Tank leak of oil to sea was closed during 2025 without any findings or penalties. 

There were eight high potential incidents in 2025. While none of these events had a material impact to health, safety or the environment in which we operate, formal investigations were conducted to ensure learning was captured to prevent recurrence. These learnings were shared across the Group and industry as applicable.

There were two Tier 1 process safety events recorded in 2025. During LPG truck loading at Akatara, a LPG loading hose detached resulting in a leak of LPG. The Akatara Gas Processing Facility ("AGPF") was shut down to avoid any escalation. There were no injuries, and an engineering solution in the form of loading arms was subsequently fitted to the loading station. At Montara, there was an observed gas leak at the Swift North 1 well, with an investigation revealing a secondary barrier failure in the 9 5/8" casing, resulting in a release of gas that is reinjected into the well to help oil recovery. The well remains shut in with an intact primary barrier, and there was no loss of reservoir fluids.

In response to several Tier III loss of primary containment events the interim COO commissioned a focus group to understand the effectiveness of asset integrity and associated systems across the Group. An action plan was developed to cover off on findings including setting up Networks of Excellence for asset integrity and process safety, independent peer reviews with SMEs from each country, Group dashboards to ensure visibility of integrity management programs and improved assurance and auditing.

To drive improvements in key areas, a line-of-sight tool was developed in Australia. The tool includes but is not limited to maintenance and reliability, hull/structural/process/well integrity, production, and HSE performance. The tool is live, interactive and visible to the workforce via Jadestone's internal intranet and is displayed in multiple locations. The tool has already proven effective in highlighting several areas that require extra focus to reduce risk exposures and additionally identify areas where systems and practices were effectively managed. Following its successful use in the Group's Australia operations, a version of the tool is being developed for the Group's Indonesia and Malaysia operations.

Jadestone's position is that, where possible, future oil and gas demand should be met through maximizing reserves and production from existing fields and discoveries, rather than exploring for and developing new sources of supply. This key pillar of the Group's strategy reflects the increasing focus on reinvestment in existing fields, as highlighted in the updated Net Zero Emissions scenario in the World Energy Outlook 2025. Jadestone's core capabilities of mature asset management and gas resource development across the Asia-Pacific region highlight the relevance of the Group's strategy in the energy transition.

Jadestone continues to make efforts to mitigate its environmental impact to as low as reasonably possible. The Group's gross Scope 1 GHG emissions during 2025 totaled 547 kilo tonnes CO2-e (2024: 587 kilo tonnes). Lower than plan GHGs were attributed to a combination of unexpected downtime in Australia, revised GHG estimation methodologies as well as lower fuel gas use trend at one of the Group's Malaysia assets.

As a key enabler of the Group's Net Zero GHG emissions pledge by 2040, the Group has committed to interim net GHG emissions reduction targets from its operated assets of 20% by 2026 and 45% by 2030 (from 2021 levels). The 2026 interim target will be achieved through direct GHG mitigation measures as well as reliance on carbon credits within the regulatory schemes of Jadestone's operating regions. A key element of the GHG mitigation plan is the upgrade of the re-injection compressor on the Montara Venture FPSO. The upgrade, which is being executed in 2026, is designed to reduce flaring-related GHG emissions, whilst also allowing for increased oil production.

GOVERNANCE

During the year, the Board and executive management refresh was completed, a process commenced in late 2024. On 16 January 2025, David Mendelson was appointed as an independent Non-Executive Director, further broadening the Board's range of expertise. Mr. Mendelson currently Chairs the Remuneration Committee and participates on the Audit Committee; Governance and Nomination Committee; and Health, Safety, Environment and Climate Committee. 

Cedric Fontenit stepped down as an independent Non-Executive Director with effect from 20 January 2025, following an orderly transition. Jenifer Thien, independent Non-Executive Director, retired from the Board on 20 June 2025 and did not seek re-election at the 2025 AGM.

Following the Board's decision, Dr. Adel Chaouch assumed the CEO's responsibilities in his capacity as Executive Chairman from 5 December 2024, to provide continuity of leadership while the search for a permanent CEO progressed. The Board was subsequently pleased to welcome Thomas Mitchell Little, appointed Chief Executive Officer on 1 June 2025 and to the Board as an Executive Director on 26 June 2025, bringing over three decades of upstream operational and senior leadership experience, including extensive international and Asia-Pacific exposure gained during his tenure with Marathon Oil.

Joanne Williams performed the duties of Chief Operating Officer on a temporary basis from 5 December 2024 until 30 September 2025. Dr. Chaouch's role as an Executive Chairman was extended on 5 December 2025 for a one-year term, with a focus on strategic initiatives to unlock and communicate the Company's underlying value. Dr. Chaouch's role will revert to Non-Executive Chairman no later than 4 December 2026.

The Board recognizes the importance of effective corporate governance in supporting the Group's long-term success and remains fully committed to maintaining high standards of governance. Following the revision of the QCA Corporate Governance Code in 2023, the Board adopted the QCA Corporate Governance Code 2023 with effect from the financial year commencing 1 January 2025. The annual statement setting out how Jadestone applied the QCA Code during the year is contained within the 2025 Annual Report.

OPERATIONAL REVIEW

INDONESIA

Akatara field, Lemang PSC (100% working interest[12], operator)

Akatara production during 2025 averaged 6,067 boe/d, compared to 977 boe/d in 2024, when the asset was brought onstream in the second half of 2024 following successful commissioning. Total production in 2025 was split roughly equally between gas and liquids (LPG and condensate). A total of 6.8 Bscf of Akatara gas was sold in 2025 at a weighted average gas price of US$5.99/Mscf, while 1.1 MMbbls of LPG and condensate were sold at a weighted average price of US$45.89/bbl, reflecting pricing benchmarks less transportation costs.

The Akatara Gas Processing Facility, which processes reservoir gas from the Akatara field into sales gas, LPG and condensate, delivered an excellent performance in 2025, its first full year of operation. Annual uptime, excluding planned downtime, at 94.4% was ahead of expectations.

The HSE performance at Akatara remains highly impressive, with over 9.3 million manhours having been worked to date in both the development and production phase without a lost-time injury.

The scheduled annual shutdown at Akatara was successfully executed in May 2025, with a focus on addressing outstanding work scopes to close out the EPCI contract and implementing upgrades to enhance the reliability and throughput of the AGPF and its ability to recover from process upsets.

The first phase of the debottlenecking project to increase the AGPF's capacity was also executed during the May 2025 shutdown, accelerating 0.8 MMboe of reserves and increasing the technical potential of the plant to 6,800 boe/d. The second phase of the debottlenecking project would involve re-routing the fuel gas source point at the AGPF upstream, optimizing the flow of hydrocarbons through the plant and potentially increasing sales gas, condensate and LPG volumes. Concept studies, engineering and value analysis for the second phase will be undertaken in 2026, ahead of a decision to implement the work 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 being insufficient to fulfill the seismic acquisition. Existing 2D seismic is currently being reprocessed to determine potential drilling candidates.

AUSTRALIA

CWLH (33.33%, non-operator)

During 2025, Jadestone's net production from the CWLH fields averaged 3,518 bbls/d, compared to 3,711 bbls/d in 2024. Although there was a full period contribution in 2025 from the additional 16.67% interest in the asset which was acquired in February 2024, which was more than offset by weather-related facilities downtime early in 2025 and scheduled downtime later in the year to test the asset's emergency shutdown systems and procedures offset this full year contribution. Outside these factors, CWLH's underlying performance remained robust, achieving almost 100% uptime over the period from May to November 2025 and producing above 4,000 bbls/d net to Jadestone for several consecutive months during the year.

During 2025, the CWLH JV planned for a scheduled drydock of the Okha FPSO. The FPSO went off station in March 2026, with production currently expected to restart around end-May 2026.

The Group lifted two CWLH cargoes totaling 1.3 MMbbls in 2025, with a weighted average realized price of US$75.57/bbl (Brent price of US$75.26/bbl and a premium of US$0.31/bbl). This compares to an average realization of US$82.38/bbl (Brent US$83.20/bbl and a discount of US$0.82/bbl) for the two cargoes lifted in 2024 (Brent US$83.20/bbl and a discount of US$0.82/bbl)

MONTARA (100% working interest, operator)

The Montara fields averaged 4,281 bbls/d in 2025, compared to 5,262 bbls/d in 2024. The year-on-year decrease is primarily explained by downtime associated with the extended drilling operations at the Skua-11 side-track well ("Skua-11ST")and also the impact of an unusual, late-season, severe weather system offshore western Australia in April 2025 which passed directly over Montara.

The Skua-11ST well commenced drilling in April with the dual objectives of decommissioning the original Skua-11 well and drilling a sidetrack into the Skua structure up-dip of the original well path. The Skua-11ST well achieved its main aims, being the acceleration and increase in recovery of reserves from the Skua structure, extending the economic life of Montara by one year and reducing unit operating costs.

In September 2025, the Group received a General Direction from NOPSEMA, Australia's offshore energy regulator, requiring that Jadestone take several actions to restore the hull integrity of the Montara Venture FPSO by making permanent temporary or defined life repairs and ensuring that the condition of the FPSO did not present a risk to the safety of the facility's personnel. The Group has complied with three of the five General Direction requirements and there has been significant progress, and engagement with NOPSEMA on, the remaining two.

During 2025, Jadestone continued to evaluate the potential for a development of the Montara licenses' gas resources at the end of commercial life of the existing oil development. Evaluation will continue throughout 2026 as concepts are matured with input from various contractors.

An increase in available FPSO crude tank capacity in the early part of 2025 allowed for a return to Free on Board cargoes, resulting in higher lifting parcels and a reduction in lifting related costs. In total, four cargoes totaling 1.6 MMbbls (2024: seven cargoes of 1.9 MMbbls) were lifted from Montara in 2025, with an average realization of US$72.21/bbl (consisting of an average Brent price of US$69.53/bbl and average premium of US$2.68/bbl). This compares to an average realization of US$83.68/bbl in 2024 (Brent US$80.20/bbl and premium US$3.48/bbl).

STAG (100% working interest, operator)

Stag field production averaged 2,032 bbls/d in 2025, compared to 2,006 bbls/d in 2024. The positive impact of workover activity and active management of electric submersible pumps in the field's wells was offset by weather impacts early in the year and mechanical issues in wells requiring workovers to restore output. The Stag-48H well, one of the more productive wells in the field, remains offline pending an engineered workover solution.

Work continues on the Stag-52H and 53H infill drilling targets to improve payback duration and returns prior to a sanction decision on either well.

The Group sold three Stag cargoes totaling 0.7 MMbbls in 2025 (2024: three cargoes of 0.7 MMbbls). Premiums for Stag crude remained robust, with the average realization for 2025 sales of US$80.72/bbl (Brent US$69.73/bbl and premium US$10.99/bbl), compared to a realized price of US$95.93/bbl in 2024 (Brent US$82.18/bbl and premium US$13.75/bbl) in 2024.

In late March 2026, the Stag field facilities were damaged by Cyclone Narelle, a Category Five storm with sustained wind speeds in excess of 200 km/hr. The facilities were safely demobilized and shut-in prior to the storm, ensuring there was no release of hydrocarbons to the environment. The main storm damage was to the field's CALM buoy, through which shuttle tankers offload crude produced from Stag. Efforts are underway to ready the CALM buoy for tow to shore where a full damage assessment will be undertaken to inform next steps.

MALAYSIA

PM323 PSC (60% working interest, operator)

The PM323 PSC produced an average of 2,423 bbls/d net to Jadestone's working interest in 2025 (2024: 3,484 bbls/d). The year-on-year decrease was primarily due to natural decline following higher production rates as a result of the Phase 8 drilling campaign in 2023.

Further infill drilling on the East Belumut field is planned in 2026, focusing on the undrained southwestern area of the field discovered during the 2023 drilling campaign. A two firm, one contingent, well campaign commenced in April 2026, with first oil expected around mid-year. The Group is also progressing an extension to the existing term of the PM323 PSC.

A total of 0.4 MMbbls (2024: 0.6 MMbbls) was lifted from the PM323 PSC during 2025, with an average realization of US$70.23/bbl (2024: US$84.30/bbl).

PM329 PSC (100% working interest, operator)

The PM329 PSC produced an average of 1,063 boe/d net to Jadestone's 70% working interest in 2025, consisting of 849 bbls/d of oil and 1.3 MMscf/d of gas (2024: 1,501 boe/d, consisting of 1,024 bbls/d of oil and 2.9 MMscf/d of gas). The year-on-year decrease is due to natural decline and higher gas reinjection levels to control water cut in the oil wells.

A total of 0.2 MMbbls of oil (2024: 0.3 MMbbls) was lifted from the PM329 PSC in 2025, with an average realization of US$69.49/bbl (2023: US$83.89/bbl). In addition, approximately 0.3 Bcf of gas was sold at an average realization of US$2.14/Mscf.

Effective 1 January 2026, the Group's partner in the PM329 PSC withdrew, increasing Jadestone's interest to 100%.

Puteri Cluster (100% working interest, operator) and PM428 PSC (60% working interest, operator)

The Puteri Cluster PSC contains the Penara, Puteri-Padang and North Lukut fields, assets in which Jadestone previously held a 50% non-operated interest (through the PM318 and AAKBNLP PSCs) following the Group's entry into Malaysia in August 2021.

The Group is continuing its technical assessment of the Puteri Cluster PSC ahead of a decision to submit a field development and abandonment plan to PETRONAS.

The PM428 PSC is adjacent to the PM323 and PM329 PSCs and surrounds the Puteri Cluster PSC. The license carries a minimal financial commitment to reprocess existing seismic and contains several prospects which, in a success case, could be developed through existing infrastructure currently operated by Jadestone.

VIETNAM

Block 51 (100% working interest, operator) and Block 46/07 (100% working interest, operator) PSCs

In March 2025, the Group announced that it had submitted a field development plan ("FDP") for the Nam Du/U Minh ("ND/UM") gas discoveries offshore southwest Vietnam, to the industry regulator Petrovietnam, commencing the regulatory approval process. The FDP was formally approved by the Vietnam Government on 18 March 2026, paving the way for initial gross 2P reserve bookings for the project of approximately 32 MMboe and for the Group to expedite discussions with interested farm-in partners. The Gas Sales and Purchase Agreement for the supply of gas from ND/UM was signed in April 2026.

The ND/UM FDP proposes a development concept based on an unmanned wellhead platform located at each field, each with two production wells, tied back to a gas processing FPSO. Gas would be exported through a 34km pipeline tied into an existing trunkline to the Ca Mau industrial complex onshore, with a planned plateau production rate of 80MMscf/d. The FDP sets out a phased development, with Nam Du being brought onstream initially, accelerating first gas to the buyer and revenues to the project partners, which will help fund the development of U Minh during the second phase.

In September 2025, Jadestone issued the contract tenders for the leased FPSO and the engineering, construction and installation of the wellhead platforms and pipelines. Evaluation of the bids received in response to these tenders is currently ongoing with Jadestone intending to award these respective contracts during the second half of the year.

The Group continues to work with Petrovietnam to obtain a suspension of the relinquishment obligation for the Tho Chu discovery in license block 51.

THAILAND

Sinphuhorm (9.52% working interest, non-operated)

On 16 April 2025, the Group announced that it had sold its Thailand interests, including its stake in the Sinphuhorm gas field, to a subsidiary of PTTEP, the Thailand national oil and gas company, for a cash consideration of US$39.4 million, with a further US$3.5 million in contingent payments depending on future license extensions.

2025 production net to Jadestone was 445 boe/d, representing production of 1,222 boe/d up to the divestment date expressed on an annualized basis.

Reserves and resources

As at 31 December 2025, the Group had 2P Reserves of 56.2 MMboe, representing a decrease compared with 31 December 2024, after accounting for production in 2025. 2P reserves of 3.6 MMboe in Thailand were removed following the disposal of the Group's interest in Sinphuhorm field in Thailand in April 2025. Downward technical revisions were recorded in Australia, reflecting actual reservoir performance and revised timing of infill and workover projects at the Skua field. Minor technical revisions were also recorded in Malaysia. In March 2026, the Group booked approximately 32.1 MMboe of 2P reserves, relating to Nam Du/U Minh offshore Vietnam following approval of the development plan for the fields. Of the 32.1 MMboe, 30.2 MMboe was a transfer from 2C resources with the remainder due to technical revisions.

Sproule ERCE independently evaluated the Group's year-end 2025 reserves.

Group 2C resources as at 31 December 2025 are estimated at 121.7 MMboe, a slight decrease of 3% year-on-year, mainly reflecting the removal of 2C resources associated with the disposal of the Group's interest in the Sinphuhorm field in Thailand in April 2025. Following the field development plan approval for Nam Du / U Minh referenced above, 30.2 MMboe of Vietnam 2C resource was transferred to 2P reserves.

FINANCIAL REVIEW

The following table provides select financial information of the Group, which was derived from, and should be read in conjunction with, the consolidated financial statements for the year ended 31 December 2025.

Benchmark commodity price and realized price

The average realized price decreased 13% in 2025 to US$74.42/bbl (2024: US$85.21/bbl), primarily reflecting movements in underlying benchmark oil prices, with the average realized Brent price reducing by 13% to US$71.25/bbl in 2025 (2024:US$81.45/bbl). The average premium reduced by 16% to US$3.17/bbl (2024: US$3.76/bbl), reflecting the move in the underlying price.

Production and liftings

Production for 2025 was 19,829 boe/d, an increase of 1,133 boe/d compared to 18,696 boe/d in 2024.

The increase was driven by the following key factors:

l Akatara added 5,090 boe/d in its first full year of production, with average production in 2025 of 6,067 boe/d compared to annualized production rate of 977 boe/d in 2024 following first gas on 31 July 2024.

l Stag production in 2025 increased by 26 bbls/d to 2,032 bbls/d (2024: 2,006 bbl/d).

l PenMal Assets production decreased by 1,499 boe/d to 3,486 boe/d in 2025 (2024: 4,985 boe/d), primarily due to natural decline following higher production rates as a result of the Phase 8 drilling campaign in 2023 and operational issues that reduced output.

l The sale of the Group's interest in Sinphuhorm reduced production by 1,310 boe/d to 445 boe/d on an annualized basis (2024: 1,755 boe/d).

l Montara's production decreased by 982 bbls/d to 4,281 bbls/d (2024: 5,262 bbls/d). Incremental production from the Skua-11ST well was offset by extended downtime during the drilling program and reduced water tank storage capacity in the second half of the year due to inspection activities.

l CWLH production was reduced by 193 bbls/d to 3,518 bbls/d (2024: 3,711 bbls/d) due to higher than anticipated weather-related downtime.

In 2025, crude oil liftings declined 11% to 4.2 MMbbls (2024: 4.8 MMbbls) due to lower oil production at Montara, PenMal and CWLH.

In 2025, gas sales increased by 222% to 7.1 Bscf, due to a full year of production at Akatara (2024: 2.2 Bscf).

Akatara condensate and LPG liftings totalled 1.1 MMbbls in 2025 (2024: 150,401 bbls).

Revenue

The Group generated net revenue of US$408.1 million in 2025, an annual increase of 3% (2024: US$395.0 million). 2025 revenue comprised commodity sales of US$405.8 million (2024: US$422.5 million) and a hedging gain of US$2.2 million (2024: hedging charge of US$27.4 million).

The net annual increase of US$13.1 million was due to:

l Akatara revenues increased by US$75.4 million to US$90.3 million in 2025 (2024: US$14.9 million), reflecting the impact of a full year of production in 2025.

l Lower realized oil prices reduced sales revenues by US$51.4 million.

l Lower combined sales volumes from Montara, Stag, PenMal and CWLH reduced aggregate revenues by US$39.8 million.

l The hedging impact on revenue improved by US$29.6 million, driven by commodity swap contracts at a weighted average hedging price of US$69.65/bbl.

Production costs

Production costs decreased by US$54.2 million or 19% in 2025 to US$232.7 million (2024: US$286.9 million reclassified). The year-on-year movement was predominately due to the following factors:

l PenMal Assets production costs were US$20.9 million lower, driven by a US$5.2 million reduction in Puteri Cluster costs, as only standby costs were incurred compared with operating costs in 2024; US$4.7 million lower inventory movements; US$4.2 million lower activity‑based other repairs and maintenance; US$3.8 million lower supplementary payments due to reduced realized prices and production volumes; and US$2.9 million in logistics savings from a support vessel cost sharing agreement.

l CWLH production costs were US$20.7 million lower, primarily due to one-off technical accounting impacts in 2024 following the acquisition of an additional 16.67% interest in February 2024. Production costs in 2025 reflect a normalized expenditure level.

l Stag production costs were US$20.1 million lower, driven by US$8.3 million lower workover activity, US$7.2 million reduced activity-based other repairs and maintenance, and a US$4.6 million net reduction in tanker rates, crude consumption, and inventory movements.

l Montara production costs were US$1.8 million lower due to lower shuttle tanker usage (extra storage vessels used in 2024) and reduced chemical consumption during the 2025 drilling‑related shutdown this was partially offset by crude lifting timing impact of US$4.3 million.

l Akatara costs increased US$9.3 million, reflecting a full year of production in 2025.

The adjusted unit operating cost per barrel of oil equivalent for 2025 was US$28.02/boe (2024: US$35.28/boe), primarily driven by a change in the production mix. The 2025 portfolio reflected a higher proportion of lower‑cost volumes from Akatara, offsetting the reduced contribution from Stag and Montara. Please refer to the non-IFRS measures section later in this document for the calculation of adjusted unit operating cost per barrel of oil equivalent.

Depletion, depreciation and amortization ("DD&A")

DD&A expenses increased by US$7.1 million to US$99.5 million in 2025 (2024: US$91.4 million). The year‑on‑year increase was primarily driven by Akatara DD&A charges of US$14.3 million, offset by lower DD&A expenses at Montara, PenMal Assets and CWLH, consistent with reduced production from those assets. The weighted average depletion unit rate decreased to US$11.82/boe (2024: US$12.45/boe), reflecting a shift in the production mix from higher unit DD&A Australian assets to lower unit DD&A production at Akatara.

In 2025, the Group's right‑of‑use asset depreciation decreased by US$3.9 million to US$12.3 million (2024: US$16.2 million). The reduction was primarily attributable to the lower level of production from Montara during the year, with the asset holding the majority of the Group's material leases.

Administrative staff costs

Administrative staff costs decreased US$0.8 million to US$23.8 million (2024: US$24.6 million), reflecting a net US$1.0 million lower severance payments in 2025 compared to 2024. The average onshore headcount for 2025 was 265, compared to 252 in 2024. The share-based payment reserve increased by US$0.9 million, reflecting the grant of share-based long term incentive awards during 2025.

Other expenses

Other expenses increased US$25.9 million in 2025 to US$49.7 million (2024: US$23.8 million reclassified), predominately due to:

l Plug and abandonment expenses written off in 2025 totalled US$18.5 million (2024: US$Nil), relating to the abandonment of the original Skua‑11 well during the Skua‑11ST drilling campaign.

l Assets written off increased US$6.9 million to US$8.7 million in 2025 (2024: US$1.8 million), primarily due to the write‑off of the original Skua‑11 well after it was plugged and abandoned following the Skua‑11ST drilling.

l The allowance for slow‑moving materials and spares decreased US$0.6 million to US$1.1 million (2024: US$1.7 million). Inventory disposal decreased US$0.3 million in 2025 year-on-year.

Finance costs

Finance costs in 2025 were US$52.9 million (2024: US$45.1 million), with the increase of US$7.8 million predominately due to:

l Accretion expenses for the asset retirement obligation ("ARO") increased by US$5.7 million to US$28.2 million in 2025 (2024: US$22.5 million), primarily due to changes in underlying assumptions and the unwinding of timing differences.

l Interest on the RBL Facility was higher by US$2.5 million to US$18.9 million in 2025 (2024: US$ 16.4 million). In 2024 US$5.1 million of interest was capitalized for the Akatara development, whereas no interest was capitalized in 2025. This was partly offset by a US$2.6 million reduction in 2025 interest expense due to borrowings reducing by US$50.0 million during the year.

l The accretion expense on the Akatara long‑term VAT receivable decreased by US$1.3 million, falling to credit US$1.2 million in 2025 driven by the fair value adjustment.

l Upfront fees and interest associated with the Working Capital Facility and other financing facilities decreased by US$0.9 million to US$1.5 million in 2025 (2024: US$2.4 million).

l Lease accretion reduced by US$1.4 million in 2025 to US$1.1 million (2024: US$2.5 million) following the expiry and renegotiation of several leases.

l Interest expense of US$3.7 million was recognized in 2025 (2024: US$Nil) following an Australian tax ruling in respect of prior year tax claims relating to the H6 well drilled in 2021. The Group is in the process of appealing the ruling.

Other income

The Group generated US$40.1 million of other income in 2025 (2024:US$29.6 million), an increase of US$10.5 million predominately due to:

l The Sinphuhorm disposal in April 2025 resulted in a net gain of US$17.5 million.

l Foreign exchange gains and derivative revaluation gains increased by US$1.0 million, arising from US$0.9 million in 2024 to US$1.9 million in 2025. In addition, interest bearing accounts and fixed deposit placements generated an extra US$0.1 million of interest income.

l Gains of US$2.1 million were recognized for Montara and Stag due to the reversal of expenses eligible for GST inputs tax credits.

l Revisions to the underlying assumptions of the ARO for PenMal assets resulted in a gain of US$3.7 million recognized in other income (2024: US$2.8 million). No revisions were recognized for CWLH assets in 2025 (2024: US$11.0 million), resulting in a net decrease of US$10.1 million in the ARO reversal items in profit or loss.

Other financial gains

Other financial gains reduced by US$1.7 million to US$0.9 million in 2025 (2024: US$2.6 million), primarily due to a lower fair value gain on revaluation of the warrant liability, which is measured at fair value at each reporting date.

In 2024, the Group recognized a gain of US$2.6 million following a significant reduction in the warrant liability from US$3.5 million to US$0.9 million. In contrast, the gain recognized in 2025 was US$0.9 million, arising from a smaller reduction in the liability from US$0.9 million to US$2,651.

Accordingly, the US$1.7 million decrease represents the lower revaluation gain recognized in the current year compared to the prior year.

Share of result of associates

The Group recognized its share of profits from its interest in the Sinphuhorm field prior to disposal in April 2025, amounting to US$1.8 million (2024: US$1.5 million).

Impairment

A pre-tax impairment charge of US$126.0 million was recognized in 2025 (2024: US$Nil). The charge relates to the impairment of oil and gas properties at Montara and Stag, amounting to US$61.2 million and US$64.8 million, respectively. After accounting for the associated deferred tax effect, the total post-tax impairment recognized was US$88.2 million.

The impairment resulted from the Group's annual impairment assessment, which concluded that the value in use ("VIU") of Stag and Montara was lower than their respective carrying values. The VIU was determined using an after‑tax discount rate of 10.0%.

Taxation

The Group recorded a tax credit of US$22.9 million in 2025, compared to a tax expense of US$0.7 million in 2024, reflecting the Group financial operating loss for the year and deferred tax movements.

The Group reported a loss before tax of US$133.7 million for 2025 (2024: US$43.4 million loss). Applying the expected weighted average effective tax rate of 39% (2024: 35%) would imply a theoretical tax credit of US$52.1 million. The actual tax outcome differs from this figure due to several asset and country specific tax impacts.

The effect of different tax rates in loss‑making jurisdictions resulted in a US$12.4 million increase in the tax credit in 2025, compared to a US$5.0 million tax charge in 2024. This reflects a change in the geographic mix of profitability and losses, particularly in jurisdictions with lower statutory tax rates or ring‑fenced tax PSC regimes.

US$21.8 million of deferred Petroleum Resource Rent Tax ("PRRT") asset was released and derecognized in 2025 (2024: utilization of US$10.0 million) which reflects the nature of PRRT and the timing of deductible expenditures. The movements in both years are predominantly attributable to deferred tax adjustments, arising from the reversal of previously recognized deferred PRRT balances that are no longer considered recoverable. In addition, the Group recognized a US$1.7 million PRRT tax refund in 2024, which did not recur in 2025.

The tax effect of non-deductible expenses was US$3.5 million in the year (2024: US$ 0.8 million), largely arising from costs that are permanently non‑deductible including certain decommissioning related costs and corporate overheads.

Income not subject to tax gave rise to a tax credit in 2025 of US$15.1 million (2024: US$1.9 million) predominately reflecting Indonesia asset cost recovery pools in excess of operating income and corporate gains not subject to tax.

Deferred tax balances not recognized in 2025 of US$9.8 million (2024: US$12.0 million) predominately relates to ARO obligations that are not expected to be recoverable as decommissioning commences at the end of the assets economic life and corporate losses due to insufficient future profits.

An adjustment in respect of prior years of US$2.8 million tax credit was recognized in 2025 (2024: US$0.8 million), mainly related to finalization of prior-year tax filings and updated assessments.

RECONCILIATION OF CASH

NON-IFRS MEASURES

The Group uses certain performance measures that are not specifically defined under IFRS, or other generally accepted accounting principles. These non-IFRS measures comprise adjusted unit operating cost per barrel of oil equivalent (adjusted opex/boe), adjusted EBITDAX, outstanding debt, and net debt.

The following notes describe why the Group has selected these non-IFRS measures.

Adjusted unit operating costs per barrel of oil equivalent (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.

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.

The calculation of adjusted EBITDAX is as follows:

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.

Net debt is defined as the sum of cash and cash equivalents and restricted cash, less the outstanding principal sum of borrowings.

Consolidated Statement of Profit or Loss and Other Comprehensive Income

for the year ended 31 December 2025

Total comprehensive loss is attributable to the equity holders of the parent.

Consolidated Statement of Financial Position as at 31 December 2025

Consolidated Statement of Financial Position as at 31 December 2025 (con't)

Consolidated Statement of Changes in Equity for the year ended 31 December 2025

Consolidated Statement of Changes in Equity for the year ended 31 December 2025 (con't)

Consolidated Statement of Cash Flows for the year ended 31 December 2025

Consolidated Statement of Cash Flows for the year ended 31 December 2025 (con't)