AIM-listed Jadestone Energy, an independent upstream production and development company and its subsidiaries, 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.
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
- Continued excellent safety and environmental performance, with Group[1] operations achieving an aggregate 13.6 million manhours lost-time injury free.
- 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] of any well drilled across all basins in Malaysia.
- 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 April 2026. Subsequently, ~32 mmboe of gross 2P reserves were booked for the initial phase of the project.
- 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 the CWLH FPSO dry dock and subsequent delays in reconnecting the FPSO and restarting production.
H1 2026 Financial Summary
- 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-based lending (“RBL”) facility.
- 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 was US$234.0 million, an increase of 3% (H1 2025: US$228.3 million).
- 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 at Stag and CWLH and increases in fuel costs due to higher oil prices.
- Adjusted EBITDAX[3] of US$101.6 million (H1 2025: US$100.6 million).
- 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 a small increase in revenue.
- 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).
- 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.
- Net debt[3] at 30 June 2026 of US$25.7 million reflected cash balances of US$174.3 million of cash (incl. restricted cash) and debt of US$200.0 million.
Guidance and Outlook
- All guidance metrics unchanged from July 2026 trading statement:
- 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 Nam Du/U Minh field facilities.
- 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 the field is expected during Q1 2027, when minor modifications to the existing mooring system will be executed prior to hook up and restart of production, which is expected during Q2 2027. The Group’s business interruption insurance cover for the current Stag shut-in runs to May 2027.
- 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.
Operational and financial summary
- 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%.
- Zero Tier 1 or Tier 2 process safety events, with a focus on asset integrity program and compliance at the Group’s operated assets.
- 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.
- 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.
- 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).
- 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.
- 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.
- Adjusted EBITDAX in H1 2026 was US$101.6 million (H1 2025: US$100.6 million).
- H1 2026 loss after tax of US$4.8 million (H1 2025: profit after tax of US$37.6 million).
- Operating cash flow before movements in working capital in H1 2026 was US$45.9 million (H1 2025: US$95.4 million).
- 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.
- 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.
[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.
Link to the full half-year 2026 results statement here.
Source: Jadestone Energy
