2025 Half Year Results

 

Strong first-half operational and financial performance

Full-year 2025 guidance reiterated

 

30 September 2025 – 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 2025 (the "financial statements"). 

 

Management will host a webcast at 9:00 a.m. UK time today, details of which can be found in the announcement below.

 

H1 2025 Operational Highlights

 

l    A total of over 11.7 million manhours worked across the Group without a lost-time injury.

l   Record production of 20,368 boe/d (H1 2024: 16,867 boe/d) from a diversified production base, representing 21% growth year-on-year, underpinned by a strong performance from Akatara.

l  T. Mitch Little appointed as Chief Executive Officer in June 2025, bringing significant operational and management experience from over three decades in the upstream industry with Marathon Oil Company.

l   Sale of Thailand assets for a total consideration of US$39.4 million, with a further US$3.5 million in cash payable contingent on future license extensions, representing active portfolio management and disciplined capital allocation.

l   In March 2025 the Group submitted a Field Development Plan ("FDP") for the Nam Du/U Minh discoveries offshore Vietnam.

l   The Skua-11ST development well at Montara was drilled safely, with initial production rates significantly ahead of expectations when brought onstream post period end.  

 

H1 2025 Financial Highlights

 

l    Profit after tax of US$32.8 million (H1 2024 loss after tax of US$31.1 million).

l    Revenues (post-hedging) of US$228.3 million (H1 2024: US$185.1 million), up 23% year-on-year.

l   Adjusted unit operating costs of US$24.70/boe (H1 2024: US$31.72/boe), down 22% year-on-year, driven by a focus on cost control across the Group.

l    Adjusted EBITDAX of US$100.6 million (H1 2024: US$60.2 million), up 67% year-on-year.

l    Operating cashflow pre working capital of US$92.8 million (H1 2024: US$27.9 million), up 232% year-on-year.

l    Closed a new US$30 million working capital facility with a 31 December 2026 maturity.

l    During the period, the Group hedged an additional 1.8 million barrels of oil production over the 12 months ending 30 September 2026 at an average Brent price of US$69.92/bbl (excluding premiums).

l   Net debt at 30 June 2025 of US$107.7 million, reflecting cash balances[1] of US$59.0 million and drawn debt of US$166.7 million. The Group received cash proceeds of US$62.5 million in July 2025 from June 2025 Montara and Stag liftings.

 

Current Trading and Outlook

 

l Continued strong production performance:

¡    Year-to-date[2], Group production has averaged approximately 20,300 boe/d, with excellent performance from Akatara.

¡    Since the beginning of June 2025, production from Akatara has averaged approximately 6,500 boe/d, thanks to an average uptime of 97.5%, supported by successful operational upgrades implemented during the scheduled May 2025 shut down and strong levels of gas demand.

l Progress on commercializing the Group's significant Vietnam gas resource:

¡    The Nam Du/U Minh FDP has been approved by Petrovietnam, the industry regulator, and is in the final stages of government approval. 

¡     The Group is also in the final stages of negotiations on a gas sales agreement for Nam Du/U Minh, and remains confident that the negotiations are heading towards a successful conclusion.

The gas sales agreement envisages a fixed gas sales price with annual escalation, and take or pay terms consistent with industry norms, providing a predictable revenue stream for Jadestone.

¡    Invitations to bid were issued for both the proposed FPSO for Nam Du/U Minh and platform and pipeline contracts.

l All guidance metrics unchanged:

¡    2025 average production of 19,500-21,500 boe/d.

¡    2025 operating costs of US$240-280 million.

¡    2025 capital expenditure of US$105-115 million.

¡    2025-2027 free cash flow (pre debt servicing) guidance[3] of US$270-360 million.

l    Net debt at 31 August 2025 was US$53.5 million, reflecting cash balances of US$113.3 million and drawn debt of US$166.7 million.

l   The Group continues to explore strategic opportunities to complement its organic growth activities, drive value and deliver scalable growth.

 

Dr. Adel Chaouch, Executive Chairman of Jadestone, commented:

 

"Jadestone delivered a strong set of results in the first half of 2025, with our focus on operational excellence and financial discipline beginning to pay off.

 

Our strategy remains clear. We will continue to work diligently on optimizing the value of our producing asset base, including managing our mature assets to maximize their economic lives and push out the point of abandonment. In parallel, we continue to advance several organic and inorganic growth initiatives, with strong momentum in recent months as we progress our Vietnam gas discoveries with the Nam Du/U Minh FDP approval and Gas Sales Agreement. We remain confident that both will be finalized in the near-term, allowing us to push forward with the commercialization of this significant gas resource.

 

We remain focused on unlocking the underlying value we believe exists in Jadestone's portfolio that is not reflected in the current share price, for the benefit of our shareholders."

 

T. Mitch Little, Chief Executive Officer of Jadestone, commented:

 

"We delivered record production in the first half across our diversified portfolio, primarily driven by a full period of Akatara production, with this asset continuing to outperform the expectations set at the beginning of 2025. Our cost performance in the period was also notable, with adjusted unit operating costs reduced by 22% year-on-year. Higher revenues and lower costs, coupled with the gain from the sale of our Thailand assets in April, allowed us to generate our first H1 profit after tax since 2022.

 

The excellent first half performance was delivered against a backdrop of safe operations, with over 11.7 million manhours worked across the Group since our last lost-time injury. We will look to build on the first half performance by expanding margins further without compromising the safety of our people or the integrity of our assets.

 

The sale of our Thailand assets, a new working capital facility, cost optimization and additional oil price hedges all combined to strengthen our liquidity and financial position in the period. With uncertainty over oil prices in the near-term, the operational and financial discipline of the business is a continuing priority for Jadestone. With strong performance from Akatara and CWLH, and the initial contribution of the Skua-11ST well, we are reiterating our 2025 production guidance today following the upgrade in July. Both operating cost and capex guidance, as well as our 2025-2027 free cash flow guidance, are also unchanged."

 

 

 

2025 FIRST HALF RESULTS SUMMARY

 

USD'000 except where indicated	Six months ended 30 June 2025	Six months ended 30 June  2024	Twelve months ended 31 December 2024
Total hours without a life-altering event (million)	0.94	3.91	5.42
Total lost-time injury rate	0.00	0.25	0.18
Production, boe/day1	20,368	16,867	18,696
Sales volume, barrels of oil (bbls)	2,398,029	2,237,259	4,764,875
Realized oil price per barrel (US$/bbl)2	77.45	88.73	85.21
Gas sales, thousand standard cubic feet (mscf)	3,480,579	559,888	2,216,652
Realized gas price per thousand standard cubic feet     (US$/mscf)	5.59	1.64	3.91
Sales volume for LPG and condensates, barrel (bbls)	514,534	-	150,401
Realized LPG and condensate price per barrel   (US$/bbl)	49.82	-	56.69
Revenue3	228,264	185,060	395,036
Production costs	(114,565)	(136,324)	(276,969)
Adjusted unit operating costs per barrel of oil equivalent     (US$/boe)4	24.70	31.72	33.68
Adjusted EBITDAX4	100,626	60,215	127,895
Profit/(Loss) after tax	32,796	(31,119)	(44,141)
Profit/(Loss) per ordinary share: basic and diluted (US$)	0.06	(0.06)	(0.08)
Operating cash flows before movements in working capital	92,847	27,946	70,526
Capital expenditure	69,381	47,618	74,459
Net debt (period end)4	(107,706)	(69,131)	(104,774)

 

Operational and financial summary  

 

l     Total hours without life altering events totaled 0.9 million manhours (H1 2024: 3.9 million manhours), with manhours worked year-on-year reduced following completion of the Akatara project during 2024.

l      Zero Tier 1 or Tier 2 process safety events, with a focus on asset integrity programs and compliance at the Group's operated assets.

l       Average production in H1 2025 increased 20.8% year-on-year to 20,368 boe/d (H1 2024: 16,867 boe/d). The growth was primarily driven by a full period of Akatara, CWLH output following the acquisition of an additional 16.67% working interest in February 2024 and improved Stag production due to fewer workover activities compared to H1 2024. These gains were partly offset by lower Montara output, impacted by weather-related downtime, subsea well shut-ins for the Skua-11ST drilling campaign, and natural field decline at the Group's Peninsular Malaysia assets ("PenMal Assets").

l      Oil liftings totaled 2.4 mmbbls in H1 2025, marginally higher than H1 2024 (2.2 mmbbls), primarily driven by increased production in H1 2025. Sales of LPG and condensate from Akatara in H1 2025 totaled 0.5 mmbbls (H1 2024: nil), while total gas sales increased significantly year-on-year (H1 2025: 3.5 bcf vs H1 2024: 0.6 bcf) driven by a full period of Akatara production.

l      The average oil price realized, excluding the effect of hedging for H1 2025, was US$77.45/bbl, a 12.7% decrease from US$88.73/bbl in H1 2024. This was driven by a lower realized Brent price (H1 2025 US$73.81/bbls vs H1 2024 US$84.14/bbl) and a lower average realized premium (H1 2025 US$3.64/bbl vs H1 2024 US$4.59/bbl).

l     The average LPG and condensate price realized was US$49.82/boe (H1 2024: nil), reflecting pricing benchmarks minus transportation costs. The average gas price realized during the period was US$5.59/mcf (H1 2024: US$1.64/mcf), benefitting from a full period of sales from the Akatara field. 

 

l     H1 2025 revenue totaled US$228.3 million, a 23.3% increase reflecting the increase in lifted volumes described above, partially offset by lower average realized oil prices. H1 2025 and H1 2024 revenue reflect a hedging charge of US$2.7 million and US$15.4 million respectively from commodity swap contracts.

l       Reported production costs reduced 15.9% to US$114.6 million in H1 2025, (H1 2024: US$136.3 million). The decrease was mainly due to changes in inventory movements, partly offset by the inclusion of production costs from Akatara. Excluding the impact of inventory movements and underlift, production costs decreased by 12.2%, from US$116.4 million in H1 2024 to US$102.2 million in H1 2025, reflecting a focus on cost control by the Group.

l      Adjusted EBITDAX increased to US$100.6 million from US$60.2 million in H1 2024, due to higher revenue and lower production costs.

l        Net profit after tax in H1 2025 was US$32.8 million (H1 2024: net loss US$31.1 million).

l      Operating cash flow before movements in working capital significantly increased in H1 2025 to US$92.8 million from US$27.9 million in H1 2024.

l      Capital expenditure in H1 2025 totaled US$69.4 million, an increase of 45.8% compared to H1 2024 at US$47.6 million, primarily due to expenditure on the Montara Skua-11ST well.

l      Net debt of US$107.7 million as at 30 June 2025 (30 June 2024: US$69.1 million net debt), reflecting US$166.7 million⁵ drawn from the RBL facility and total cash and cash equivalents of US$59.0 million.

 

¹ Production includes the 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.

² Realized oil price represents the actual selling price inclusive of premiums, excluding the effect of hedging.

³ Revenue in H1 2025 and H1 2024 include hedging losses of US$2.7 million and US$15.4 million respectively.

⁴ Adjusted unit operating costs per 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.

⁵ RBL borrowing base account reduced from US$200 million to US$166.7 million following principal repayment of US$33.3 million in April 2025.

 

 

For further information, please contact:

 

Jadestone Energy plc
Phil Corbett, Head of Investor Relations	+44 (0) 7713 687467 (UK)
	[email protected]
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 3757 4980 (UK)
Ciaran Walsh
Dan Gee-Summons
Ryan Mahnke
Camarco (Public Relations Advisor)	+44 (0) 203 757 4980 (UK)
Billy Clegg	[email protected]
Georgia Edmonds
Poppy Hawkins

 

 

 

 

Webcast

 

The Company will host an investor and analyst presentation at 9:00 a.m. (BST) on Tuesday, 30 September 2025, including a question-and-answer session, accessible through the link below:

 

Webcast link: https://www.investis-live.com/jadestone-energy/68c29527c6edb50015a739b5/ggdsfs   

Event title: Jadestone Energy plc First-Half 2025 Results

Time: 9:00 a.m. (BST)

Date: 30 September 2025

 

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=88676   

Access Code: 368891

 

 

 

 

 

 

Health, Safety and Environment ("HSE")

 

	Six Months ended 30 June 2025	Six months ended 30 June 2024	Twelve months ended 31 December 2024
Total hours without a life altering event	936,466	3,909,124	5,418,258
Total lost-time injury rate	0.00	0.25	0.18

 

The Group continued its strong safety performance in the first half of 2025, and on 17 May 2025 achieved the milestone of one year without a lost-time injury. During the period, the Group reported zero life altering events, no significant impacts to the environment, zero regulatory enforcement notices, and no Tier 1 or 2 process safety loss of primary containment events ("LOPC"). There was a 82% year-on-year reduction in recordable injuries for the six-month period ending June 2025 and a 100% reduction in lost workday cases over the same period. Jadestone's combined operations worked over 3.9 million manhours in H1 2025.

 

There were several high potential events ("HiPo") across the Group during the first six months of 2025. While  there were no major injuries, and no harm to the environment, the HiPo events were fully investigated, corrective actions raised to address route cause and the lessons learned shared across the Group. During 2025, the Group focused on several 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. The PSF rules will be implemented across the Group in the second half of 2025. 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.

 

During the period, there was further progress on the Montara Venture FPSO tank inspection and repair program, with crude oil tank 2C returned to service for the first time since June 2022. This milestone allowed for greater flexibility in the marketing and sale of Montara oil production, particularly the return to Free On Board ("FOB") cargo sales, which reduce lifting related costs. In total, ten tanks have been removed from the NOPSEMA Prohibition Notice and returned to service. Four crude oil tanks remain to be inspected and any repairs made before removal from the Prohibition Notice, with this activity expected to be complete in the first half of 2026.  

 

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. The safety of Jadestone's people and assets is a priority for the Group, and Jadestone will fully comply with the General Direction. Many of the tasks necessary to meet the General Direction's requirements had previously been identified by the Group's new leadership team, with work already underway to address them. The Group expects that any incremental activity required to comply with the General Direction will not have a meaningful operational impact, nor will it have an impact on the Group's operating cost guidance, which remains unchanged.

 

ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG")

 

Jadestone is committed to being a responsible operator that contributes to an orderly energy transition by helping to meet regional energy demand, while bringing positive social and economic benefits for its stakeholders, local communities and the people associated with its operations. Performance across key ESG areas during the half year ended 30 June 2025 is set out below.

 

GHG emissions and Net Zero targets

 

Jadestone's business strategy focuses on maximizing value from existing producing oil and gas fields, explicitly excluding frontier exploration and new greenfield developments. This approach aligns with the IEA's Net Zero Emissions by 2050 Scenario, maintaining the Group's strategic relevance in the face of energy transition. As a responsible steward of mid-life assets, Jadestone is committed to upholding climate targets and executing its Net Zero by 2040 pledge.

 

Preliminary H1 2025 Scope 1 GHG emissions for the Group[4] amounted to 274 kt of CO₂-e, tracking below plan, mostly due to a lower trend in fuel gas usage at PM323 in Malaysia, along with an improved accuracy of fugitive emissions estimations across the PenMal operations. Lower flaring at Stag, due to a high gas well remaining offline, as well as weather and Skua-11ST impacts on Montara uptime also contributed to the lower emission trend year-to-date.

 

The Group remains committed to reducing Scope 1 and 2 absolute GHG emissions from its operated assets by 20% by 2026 and by 45% by 2030 (from 2021 levels) on its pathway to Net Zero by 2040. These interim targets will be achieved through a combination of measures, including minimizing flaring, methane quantification, monitoring and reduction as well as reliance on carbon credits within the regulatory schemes of Jadestone's operating regions.

 

The Group continues to progress plans to upgrade the re-injection compressor on the Montara Venture FPSO, which will be an important cornerstone of Jadestone's Net Zero implementation roadmap to 2030. The initiative is designed to reduce flaring-related GHG emissions and will also allow for increased oil production, with project execution scheduled for H1 2026.

 

Governance

 

Jadestone's Board saw a number of changes in the first half of 2025. These changes reflect a longer-term objective to align the Board's size with the Group's scale and ambitions, while ensuring the right mix of capabilities and adherence to corporate governance standards.

 

On 16 January 2025, the Company announced the appointment of David Mendelson as an independent Non-Executive Director. Upon his appointment, Mr. Mendelson serves as a member of the Audit Committee, the Governance and Nominating Committee, and the Remuneration Committee.

 

Also on 16 January 2025, the Company announced that Cedric Fontenit had signaled his intention to step down as a Non-Executive Director of the Company with effect on 20 January 2025 and following a term exceeding nine years, to focus on other business interests.

 

On 20 May 2025, Jenifer Thien signaled an intention not to seek re-election as an independent Non-Executive Director at the Company's Annual General Meeting on 20 June 2025. Ms. Thien's appointment ended effective 20 June 2025.  Mr. Mendelson assumed the role of Chair of the Remuneration Committee on that same date.

 

On 2 June 2025, the Company announced the appointment of T. Mitch Little as the Chief Executive Officer ("CEO"), effective 1 June 2025. On 26 June 2025, the Company announced the appointment of Mr. Little to its Board of Directors as an Executive Director.

 

In December 2024, Joanne Williams accepted the role of Chief Operating Officer ("COO") on a temporary basis while the search for a new CEO was progressed (see immediately above). Following the appointment of T. Mitch Little as CEO and a restructuring of the Group's operational management, Joanne Williams stepped down as interim COO at the end of September 2025, but remains in her role as an independent Non-Executive Director.

 

Dr. Adel Chaouch continues to serve as Executive Chairman of the Company.

 

 

OPERATIONAL REVIEW

 

Australia

 

Montara Project (100% working interest, operator)

 

The Montara fields production averaged 4,229 bbls/d in H1 2025, compared to 4,951 bbls/d in H1 2024. The year-on-year decrease is primarily explained by downtime associated with scheduled maintenance and also the impact of an unusual, late-season, weather system offshore western Australia in April 2025 which passed directly over Montara. Production was also curtailed at times for operational and safety reasons during the drilling and completion of the Skua-11 side-track well ("Skua-11ST").

 

The Skua-11ST well commenced drilling in April and reached target depth in July. Analysis of well logs confirmed the presence of over 900 meters of high-quality reservoir, more than double the reservoir section completed in any of the previous Skua wells.  Production commenced in early August, with initial oil production rates from the well exceeding 6,000 bbls/d, significantly ahead of previous guidance of 3,500 bbls/d.

 

Skua-11ST was completed with downhole inflow control devices, which are designed to maximize reservoir sweep and recovery from the well. Skua-11ST, along with the other Montara wells, will be managed in the longer-term to maximize overall recovery from the Montara field.

 

During the first half of 2025, there were two liftings from Montara totaling 0.9 mmbbls (H1 2024: three cargoes totaling 0.8 mmbbls), with an average realization of US$75.14/bbl (consisting of an average Brent price of US$72.83/bbl and average premium of US$2.31/bbl). This compares to an average realization of US$88.35/bbl in H1 2024 (Brent US$83.82/bbl and US$4.53/bbl premium).

 

CWLH (33.33% working interest)

 

During H1 2025, Jadestone's net production from the CWLH fields averaged 3,311 bbls/d, compared to 2,951 bbls/d in H1 2024. The year-on-year change is primarily explained by a full period contribution in H1 2025 from the 16.67% interest in the asset acquired in February 2024, offset by weather-related facilities downtime early in 2025.         

 

The Group lifted one cargo of 0.7 mmbbls from CWLH in H1 2025 with a realized price of US$78.86/bbl (Brent price of US$79.23/bbl and a discount of US$0.37/bbl). This compares to a realization of US$86.39/bbl (Brent US$85.49/bbl and a premium of US$0.90/bbl) for the one cargo of 0.7 mmbbls lifted in H1 2024.

 

Stag (100% working interest, operator)

 

Stag field production averaged 2,209 bbls/d in H1 2025, compared to 1,921 bbls/d in H1 2024. Stag production during the period benefitted from higher rates due to successful Proportional-Integral-Derivative trials on the electric submersible pumps in the field's wells. If sustained over a longer period, these results may also reduce workover frequency associated with ESP failures, yielding sustainable operating cost savings. Higher production rates were partially offset by weather-related downtime early in 2025.

 

The Group sold two Stag cargoes totaling 0.5 mmbbls in H1 2025 (H1 2024: one cargo of 0.2 mmbbls). Premiums for Stag crude have remained strong, with the average realization for H1 2025 sales of US$83.04/bbl (Brent US$70.49/bbl and premium US$12.55/bbl), compared to a realized price of US$101.37/bbl (Brent US$85.49/bbl and premium US$15.88/bbl) in H1 2024.

 

 

Indonesia

 

Akatara (100% working interest[5], operator)

 

The first half of 2025 represented the first full period of production operations at the Akatara development onshore Indonesia, following completion of the EPCI contractual performance test in December 2024. This milestone marked the conclusion of the commissioning phase at Akatara, with responsibility for day-to-day operations at the Akatara gas processing facility ("AGPF") transitioning from the EPCI contractor to Jadestone.

 

The AGPF, which processes the raw wet gas from the Akatara field into sales gas, LPGs and condensate, delivered an excellent performance in the first half of 2025. Uptime was ahead of plan at 96%, resulting in average gross production of 5,771 boe/d from the field, split equally between gas and liquids production. This compared to 3 boe/d of average production from the field in H1 2024, representing initial commissioning volumes in late June 2024 averaged over the full six month period. A total of 3.2 bcf of Akatara gas was sold in H1 2025 at the contractual price of US$5.99/mcf, while 0.5 mmbbls of Akatara LPG and condensate production was sold at a weighted average price of US$49.82/bbl, reflecting pricing benchmarks less transportation costs.

 

The scheduled annual shutdown at Akatara was successfully executed in May 2025, with a focus on addressing the outstanding work scopes to close out the EPCI contract and implementing upgrades to enhance the reliability 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. With the AGPF demonstrating the ability to deliver sustainably higher gas sales, the buyer of Akatara's gas has responded with higher nominations. Since the shutdown, Akatara production has averaged approximately 6,500 boe/d, peaking at just over 7,000 boe/d.

 

The HSE performance at Akatara remains very strong, with over 8.8 million manhours having been worked to date in both the development and production phase without a lost time injury.

 

Malaysia

 

PM323 PSC (60% working interest, operator)

 

The PM323 PSC produced an average of 2,819 bbls/d net to Jadestone's working interest in H1 2025 (H1 2024: 3,839 bbls/d). The year-on-year decrease primarily reflects natural decline, with unscheduled compressor downtime also impacting production during the period.

 

During the first half of 2025, the Group continued to progress its plans for further infill drilling on the East Belumut field in 2026, in particular focusing on the undrained southwestern area of the field discovered during the 2023 drilling campaign.

 

A total of 0.2 mmbbls (H1 2024: 0.4 mmbbls) were lifted from the PM323 PSC during H1 2025, with an average realization of US$72.22/bbl (H1 2024: US$86.76/bbl), based on an average Brent price of US$70.79/bbl (H1 2024: US$82.62/bbl) and an average premium of US$1.43/bbl (H1 2024: US$4.14/bbl)

 

PM329 PSC (70% working interest, operator)

 

The PM329 PSC produced an average of 1,132 boe/d net to Jadestone's working interest in H1 2025, consisting of 861 bbls/d of oil and 1.6 mscf/d of gas (H1 2024: 1,616 boe/d, consisting of 1,103 bbls/d of oil and 3.1 mscf/d of gas). The year-on-year decrease is explained by natural decline.

 

A total of 0.1 mmbbls of oil (H1 2024: 0.1 mmbbls) were lifted from the PM329 PSC in H1 2025, with an average realization of US$71.08/bbl (H1 2024: US$86.03/bbl). In addition, 0.3 bcf of gas was sold in H1 2025 at an average realization of US$1.33/mcf.

  

 

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

 

During the period, the Group continued its assessment of redevelopment opportunities in the Puteri Cluster and potential upside in the surrounding PM428 license.

 

Thailand

 

On 16 April 2025, the Group announced that it has divested its 9.52% interest in the producing Sinphuhorm gas field onshore Thailand to PTTEP HK Holding Limited, a subsidiary of PTTEP, Thailand's national oil and gas company, for a cash consideration of US$39.4 million, with a further US$3.5 million in cash payable contingent on future license extensions.

 

Average production for H1 2025 was 898 boe/d (2024: 1,531 boe/d), based on average production up to divestment of 1,222 boe/d.  

 

Due to a lack of influence over the day-to-day operational activities at Sinphuhorm, the Group did not recognize its share of revenues and production costs up to the point of sale, instead recognizing dividend income when received from APICO LLC, the intermediary company through which Jadestone owned its interest in the asset. No dividends were received in H1 2025 prior to disposal (H1 2024: US$3.8 million).

 

Vietnam

 

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

 

In March 2025, the Group announced that it has submitted a Field Development Plan for the Nam Du/U Minh ("NDUM") gas discoveries offshore southwest Vietnam, to the industry regulator Petrovietnam, commencing the regulatory approval process.

 

The NDUM 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 Jadestone, 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.

 

The FDP successfully passed the first stage of the regulatory approval process with Petrovietnam in July 2025 and is now with the Vietnamese Ministry of Industry and Trade undergoing the final approval stage.  During the period, the Group continued to engage with stakeholders on the NDUM gas sales and purchase agreement ("GSPA"). On 30 June 2025 the gas sales heads of agreement, originally signed in January 2024, was extended by a further six months to support the FDP approvals process and allow time to complete GSPA negotiations.  The GSPA envisages a fixed gas sales price with annual escalation, and take or pay terms consistent with industry norms, providing for a predictable revenue stream. The Group remains confident that the GSPA negotiations are heading towards a successful conclusion.

 

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

 

 

 

FINANCIAL REVIEW

 

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 2025.

 

USD'000 except where indicated	Six months ended 30 June 2025	Six months ended 30 June 2024	Twelve months ended 31 December 2024
Production, boe/day1	20,368	16,867	18,696
Sales volume, barrels of oil (bbls)	2,398,029	2,237,259	4,764,875
Realized oil price per barrel (US$/bbl)2	77.45	88.73	85.21
Gas sales, thousand standard cubic feet (mscf)	3,480,579	559,888	2,216,652
Realized gas price per thousand standard cubic feet   (US$/mscf)	5.59	1.64	3.91
Sales volume for LPG and condensates, barrel (bbls)	514,534	-	150,401
Realized LPG and condensate price per barrel   (US$/bbl)	49.82	-	56.69
Revenue3	228,264	185,060	395,036
Production costs	(114,565)	(136,324)	(276,969)
Adjusted unit operating costs per barrel of oil   equivalent (US$/boe)4	24.70	31.72	33.68
Adjusted EBITDAX4	100,626	60,215	127,895
Unit depletion, depreciation and amortization   (US$/boe)	14.15	13.02	12.45
Profit/(Loss) before tax	38,073	(29,129)	(43,435)
Profit/(Loss) after tax	32,796	(31,119)	(44,141)
Profit/(Loss) per ordinary share: basic and diluted   (US$)	0.06	(0.06)	(0.08)
Operating cash flows before movements in working   capital	92,847	27,946	70,526
Capital expenditure	69,381	47,618	74,459
Net debt (period end)4	(107,706)	(69,131)	(104,774)

 

 

Benchmark commodity price and realized price

 

The actual average oil price realization, excluding the effect of hedging, decreased in H1 2025 by 12.7% to US$77.45/bbl, compared to US$88.73/bbl in H1 2024. The reduction in realized price was mainly driven by decline in the benchmark realized Brent price by 12.3% to U$73.81/bbl (from U$84.14/bbl in the H1 2024) and the average realized premium to US$3.64/bbl (from US$4.59/bbl in H1 2024).

 

The average gas price realization increased to US$5.59 mscf in H1 2025 from US$1.64 mscf in H1 2024, reflecting a first full period of gas sales from Akatara.

 

 

¹ Production includes the Sinphuhorm Asset 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.

² Realized oil price represents the actual selling price inclusive of premiums or discounts, excluding the effect from hedging.

³ Revenue in H1 2025 and H1 2024 include hedging loss of US$2.7 million and US$15.4 million respectively.

⁴ Adjusted unit operating cost per 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.

 

 

Production and liftings

 

H1 2025 average production rose by 20.8% to 20,368 boe/d from 16,867 boe/d in H1 2024. The overall increase of 3,501 boe/d was the result of the following factors:

 

·     Akatara commenced first commercial production in July 2024 and contributed production of 5,771 boe/d in H1 2025 compared to 3 boe/d in H1 2024.

·     CWLH  production for the full period of H1 2025 increased to 3,311 bbls/d from 2,951 bbls/d in H1 2024, following the completion of the acquisition of an additional 16.67% interest in February 2024 which doubled the working interest in the asset.

·      Stag H1 2025 production increased by 288 bbls/d, benefitting from reduced workover activities.

 

The above increase was partly offset by:

 

·      PenMal H1 2025 reported a decrease of 1,504 boe/d to 3,951 boe/d, primarily due to natural decline.

·     Montara H1 2025 production decreased by 722 bbls/d to 4,229 bbls/d due to weather related downtime, scheduled compressor maintenance and downtime associated with the drilling of the Skua-11ST well.

 

During H1 2025, the company lifted 2.4 mmbbls of crude oil (H1 2024: 2.2 mmbbls), 3.5 mmscf of gas (H1 2024: 0.6 mmscf) and 0.5 mmbbls of LPG and condensate (H1 2024: nil). The increase in lifted volumes reflects higher production, the timing of liftings and a full period of production and sales from Akatara.

 

Revenue

 

The Group generated gross revenues before hedging of US$231.0 million, representing a 15.2% increase over the comparable period (H1 2024: US$200.5 million).

 

The commodity swap hedge expense reduced to US$2.7 million (H1 2024: US$15.4 million), resulting in net revenue of US$228.3 million in H1 2025 (H1 2024: US$185.1 million).

 

The period-on-period increase in total net revenues of US$43.2 million is due to:

 

·     A full reporting period from Akatara contributing an additional US$44.7 million of revenue, comprising gas sales of US$19.1 million, LPG US$17.8 million and condensate of US$7.8 million;

·      Higher lifted crude volumes generating an additional US$12.5 million;

·    Hedging expense reduced by US$12.7 million year-on-year (H1 2025: US$2.7 million vs H1 2024: US$15.4 million); offset by

·   Lower realized oil prices reducing revenue by US$25.3 million (H1 2025: US$77.45/bbl vs. H1 2024: US$88.73/bbl).

 

Production costs

 

Production costs decreased US$21.8 million, or 15.9%, to US$114.6 million in H1 2025 from US$136.3 million in H1 2024, due to:

 

·       Akatara delivered first gas in July 2024 and subsequently generated production costs of US$8.4 million during H1 2025 compared to nil in H1 2024.

·     Higher lifted volumes in H1 2025 at Stag resulting in an additional inventory movement expense increasing production costs by US$5.9 million. Excluding inventory movements, actual production costs declined by 12.2% predominately as a result of lower workovers and R&M activities in H1 2025.

·     Higher lifted volumes at Montara led to increased production costs of US$1.0 million which also resulted in additional inventory movement expenses. Excluding the impact of inventory movements, actual production costs at Montara decreased by 17.2%, reflecting lower operating costs in H1 2025 compared to H1 2024, when costs for FPSO storage tank repairs and shuttle tankers were incurred 

 

·       CWLH production costs decreased by US$31.0 million compared to H1 2024, due to the technical accounting impacts of the February 2024 acquisition. At the acquisition date, an underlift of 530,484 bbls was recognized at fair market value, contributing to an inventory movement of US$33.0 million in H1 2024. Excluding the effect of inventory movements, total production costs in H1 2025 were US$1.0 million higher, reflecting a full period of production costs for the second tranche acquired in February 2024.

·     PenMal production costs decreased by US$6.1 million, primarily as there were no Puteri cluster operating costs in H1 2025, as well as lower fuel expenses and reduced repairs and maintenance compared to one-off activities in the prior period.

 

As a result of the above and higher production the adjusted unit operating cost per boe was US$24.70/bbl (H1 2024: US$31.72/bbl) (see non-IFRS measures section below).

 

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

 

Net depletion charges for oil and gas properties increased by 31.3% to US$39.4 million in H1 2025, compared to US$30.0 million in H1 2024, primarily driven by Akatara asset recorded DD&A of US$7.1 million in H1 2025 (H1 2024: nil). This increase was partially offset by lower DD&A for Montara and PenMal, consistent with lower production during the reporting period. The unit depletion cost in H1 2025 was US$14.15/boe, increasing from US$13.02/boe in H1 2024.

 

Depreciation of the Group's right-of-use assets and plant and equipment decreased to US$7.8 million in H1 2025 from US$8.2 million in H1 2024, mainly due to a diminishing lease balance for warehouse and helicopter leases approaching contract expiry, as well as pending renewal of a support vessel lease which ended in H1 2025.

 

Administrative staff costs

 

Administrative staff costs increased 5.7% to US$16.7 million in H1 2025 up from US$15.8 million in H1 2024. The H1 2025 charge includes US$1.5 million of redundancy payments, reflecting a reduction in onshore headcount to 252 at the end of 30 June 2025, compared to 282 at 31 December 2024 (30 June 2024: 274). Excluding severance costs, administrative staff costs reduced by 3.8% year-on-year.

 

Other expenses

 

Other expenses decreased by US$4.1 million in H1 2025 to US$10.2 million (H1 2024: US$14.3 million), mainly due to a provision recognized in H1 2024 for two Akatara related contingent payments totalling US$5.5 million. These payments were linked to the average Brent price and average Saudi CP¹ exceeding US$80/bbl and US$620/MT, respectively, in the first year of production. No similar provision was required in H1 2025, as future prices are not currently expected to exceed these thresholds. Professional fees were US$0.8 million higher (H1 2025: US$4.2 million; H1 2024: US$3.4 million).

 

Other income

 

Other income increased by US$17.4 million to US$24.2 million in H1 2025 (H1 2024: US$6.8 million) predominately due to a US$17.5 million gain on divestment of the Group's Thailand assets. The remaining balance relates to rebates on Montara's helicopter contract and bank interest earned.

 

 

 

¹The term "Saudi CP" typically refers to the Saudi Contract Price ("CP"), which is a benchmark price for liquefied petroleum gas ("LPG") in the global market.

 

Finance costs

 

Finance costs in H1 2025 were US$28.4 million (H1 2024: US$19.5 million), an increase of US$8.9 million, predominately due to:

 

·     Asset restoration obligations ("ARO") accretion expense increased by US$5.9 million to US$16.4 million in H1 2025 (H1 2024: US$10.5 million). The CWLH accretion expense increased in H1 2025 to US$4.9 million (H1 2024: US$2.3 million) following the acquisition of an additional share of ownership completed in February 2024. The accretion expense for PenMal's Puteri facilities increased by US$2.0 million under the fiscal terms of the Small Field Assets Cluster and the remaining balance reflected a change in discount factor.

·    RBL accretion fees and interest expenses increased by US$4.6 million to US$10.0 million in H1 2025 (H1 2024: US$5.4 million) is primarily due to interest related to the Akatara development being expensed in the period instead of being capitalized prior to first gas in July 2024.

·      Interest expense on lease payments decreased by US$0.6 million, mainly due to the vessel lease contract for Montara ending in H1 2025 and lower residual values for warehouse and helicopter lease contracts near expiry which are yet to be renewed.

·   Lending fees decreased by US$0.6 million, mainly due to standby working facility fees of US$1.2 million recognized in H1 2024, which ended on 31 December 2024, partially offset by lending fees of US$0.6 million arising from a new standby working facility entered into in April 2025.

 

Taxation

 

The income statement tax expense of US$5.3 million in H1 2025 (H1 2024: tax expense of US$2.0 million) comprised a current tax charge of US$8.6 million (H1 2024: tax charge US$7.5 million) and a deferred tax credit of US$3.3 million (H1 2024: tax credit of US$5.5 million).

 

 

USD'000	H1 2025		H1 2024
Profit/(Loss) per income statement	38,073		(29,129)
Tax Rate	34%		28%
Tax at the Country Tax Rate	10,864		(8,273)
Non-deductible expenses	547		2,809
Income not subject to tax	(9,589)		7,240
Deferred PRRT/PITA tax credit	1,871		(3,050)
Deferred tax assets not recognized in respect of current year taxes	5,958		545
Over provision prior year	(5,184)		-
Under deferred tax in prior year	810		2,719
Tax expense	5,277		1,990

 

 

 

 

 

RECONCILIATION OF CASH

 

USD'000	H1 2025		H1 20241
Cash and cash equivalent at the beginning of   period		95,226		153,404
Revenue	228,264		185,060
Other operating income2	5,176		3,525
Production costs	(114,565)		(136,324)
Administrative staff costs2	(16,420)		(15,541)
General and administrative expenses2	(9,608)		(8,774)
Operating cash flows before movements in   working capital		92,847		27,946
Movements in working capital		(57,760)		(40,271)
Net tax refunded/(paid)		1,095		(16,486)
Purchases of intangible exploration assets, oil and   gas properties, and plant and equipment3		(60,304)		(27,151)
Proceeds from the sale of Sinphuhorm Assets		39,352		-
Cash received on acquisition of CWLH		-		5,236
Dividends received from associate		-		3,768
Interest received		1,544		410
Repayment of lease liabilities		(9,326)		(8,977)
Total drawdown of borrowings		-		43,000
Repayment of borrowings		(33,252)		-
Payment of costs and interest of borrowings		(9,646)		(8,394)
Other financing activities		(734)		(1,616)
Total cash and cash equivalent at the end of   period		59,042		130,869

 

 

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.

 

 

 

 

 

 

 

¹ Certain H1 2024 comparative information has been reclassified. US$1.3 million has been reclassed from other financing activities to repayment of lease liabilities in accordance with the nature of activities.

² Other operating income, administrative staff costs and general and administrative expenses adjusted figures are non-IFRS measures.

³ Total capital expenditure was US$69.4 million (H1 2024: US$47.6 million), comprising total capital expenditure paid of US$60.3 million (H1 2024: US$27.1 million), accrued capital expenditure of US$9.1 million (H1 2024: US$16.2 million) and capitalization of borrowing costs of US$Nil (H1 2024: US$4.3 million).

 

 

 

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 defined as total production costs excluding oil inventories movement and underlift/overlift, write down of inventories, workovers (to facilitate better comparability period to period) and non-recurring repairs and maintenance.  It includes lease payments related to operational activities, net of any income earned from leasing of right-of-use assets involved in production, and excludes transportation costs, supplementary payments and royalties, costs associated with the PenMal non-operating assets and DD&A. 

 

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.

 

USD'000 except where indicated		Six months ended 30 June 2025		Six months ended 30 June 2024		Twelve months ended 31 December 2024
Production costs (reported)		114,565		136,324		276,969
Adjustments
Lease payments related to operating activities1		7,863		8,764		17,538
Underlift, overlift and crude inventories   movement2		(12,390)		(19,972)		(21,411)
Workover costs3		(2,096)		(10,633)		(20,797)
Other income4		(3,139)		(3,200)		(5,731)
Non-recurring operational costs5		-		(6,775)		(8,840)
Non-recurring repairs and maintenance6		(2,596)		(5,343)		(2,850)
Transportation costs7		(4,100)		(3,656)		(8,451)
Supplementary payments and royalties8		(11,072)		(6,324)		(17,342)
PenMal non-operated assets operational costs9		-		(994)		(262)
Adjusted production costs		87,035		88,191		208,823
Total production (barrels of oil equivalent) 10		3,524,123		2,780,677		6,200,334
Adjusted unit operating costs per barrel of oil   equivalent		24.70		31.72		33.68

                                                                                                                                                                                         

 

¹ 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.

² Underlift, overlift and 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).

³ Workover costs are excluded to enhance comparability. The frequency of workovers can vary significantly, across periods.

⁴ Other income represents the rental income from a helicopter rental contract (a right-of-use asset) to a third party.

⁵ There are no non-recurring operational costs incurred in H1 2025. The cost during H1 2024 related to costs incurred at Montara being interim tanker storage temporarily employed as a result of the repair work relating to the storage tanks of the FPSO.

⁶ Non-recurring repairs and maintenance costs in H1 2025 predominately related to tank maintenance at Montara, and CALM buoy coating remediation and maintenance pigging of export flowline at Stag. The costs during H1 2024 predominately related to floating hose repair at Montara, CALM buoy coating remediation and maintenance pigging of export flowline at Stag, and rectification costs of the cranes and platforms of the Puteri Cluster at PenMal.

 

 

⁷ Transportation costs includes the pipeline tariff at PenMal and tanker costs at Stag and Montara associated with lifting costs.

⁸ PenMal Assets supplementary payments are required under the terms of PSCs based on Jadestone's profit oil 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.

⁹ No cost incurred in H1 2025 related to PenMal non-operated Asset operational costs. In H1 2024 refer to the operating costs incurred at the Puteri Cluster, which are excluded as the costs incurred were mainly related to the preservation of facilities and subsea infrastructure and do not contribute to production.

¹⁰ Gas production from the Sinphuhorm Asset 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.

 

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:

 

USD'000	Six months ended 30 June 2025		Six months ended 30 June 2024		Twelve months ended 31 December 2024
Revenue	228,264		185,060		395,036
Production costs	(114,565)		(136,324)		(276,969)
Administrative staff costs	(16,738)		(15,757)		(34,423)
Other expenses	(10,230)		(14,312)		(23,859)
Allowance for expected credit losses	-		-		(457)
Share of results of associate accounted for   using the equity method	1,849		2,124		1,553
Other income, excluding interest income	22,694		3,528		22,122
Other financial gains	872		1,001		2,611
Unadjusted EBITDAX	112,146		25,320		85,614
Non-recurring
Net loss from oil price and foreign exchange   derivatives	2,702		15,425		27,417
Non-recurring opex1	2,596		13,112		11,952
Assets written off	622		38		1,423
Net gain on disposal of an associate	(17,518)		-		-
Change in provision - Lemang PSC contingent   payments	-		5,500		-
Others2	78		820		1,489
	(11,520)		34,895		42,281
Adjusted EBITDAX	100,626		60,215		127,895

 

¹ Non-recurring opex in H1 2025 mainly represents one-off repair and maintenance costs predominantly related to Montara tank maintenance and CALM buoy coating remediation and maintenance pigging of export flowline at Stag. The H1 2024 non-recurring costs mainly represent Montara interim tanker storage costs which was temporarily employed as a result of the repair work relating to the storage tanks of the FPSO. It also includes one-off repair and maintenance costs predominately related to CALM buoy coating remediation and maintenance pigging of export flowline at Stag, and rectification costs of the cranes and platforms of the Puteri Cluster at PenMal.

² Includes business development related expenses, external funding sourcing costs, internal reorganization costs and fair value loss on contingent consideration.

 

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.

 

USD'000		Six months ended 30 June 2025		Six months ended 30 June 2024		Twelve months ended 31 December 2024
Borrowings (principal sum)		(166,748)		(200,000)		(200,000)
Cash and cash equivalents		59,042		130,869		95,226
Net debt		(107,706)		(69,131)		(104,774)

 

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

 

The Group received cash proceeds of US$62.5 million in July from June Stag and Montara liftings of 0.8 mmbbls.

 

 

2025 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 framework 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 2025, the principal risks and uncertainties faced by the Group remain consistent with those disclosed in the 2024 Annual Report on pages 24 to 28. The Group's strategies for risk mitigation also remain unchanged.

 

 

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 at least 12 months from the balance sheet date 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 2.

 

 

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).

 

By order of the Board,

 

 

 

 

 

Andrew Fairclough

Executive Director                                                                              

Chief Financial Officer                                                       

30 September 2025                                                                           

 

 

 

 

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.

 

Condensed Consolidated Statement of Profit or Loss and Other Comprehensive Income

for the six months ended 30 June 2025

 

		Six months ended 30 June 2025		Six months ended 30 June  2024		Twelve months ended 31 December 2024
		Unaudited		Unaudited		Audited
	Notes	USD'000		USD'000		USD'000
Consolidated statement of profit or loss
Revenue		228,264		185,060		395,036
Production costs	4	(114,565)		(136,324)		(276,969)
Depletion, depreciation and amortization	4	(47,265)		(38,180)		(91,407)
Administrative staff costs	4	(16,738)		(15,757)		(34,423)
Other expenses	4	(10,230)		(14,312)		(23,859)
Allowance for expected credit losses		-		-		(457)
Share of results of associate accounted for   using the equity method	11	1,849		2,124		1,553
Other income		24,238		6,779		29,614
Finance costs	5	(28,352)		(19,520)		(45,134)
Other financial gains		872		1,001		2,611
Profit/(Loss) before tax		38,073		(29,129)		(43,435)
Income tax expense	6	(5,277)		(1,990)		(706)
Profit/(Loss) for the period/year		32,796		(31,119)		(44,141)
Profit/(Loss) per ordinary share
Basic and diluted (US$)	7	0.06		(0.06)		(0.08)
Other comprehensive income/(loss)
Profit/(Loss) for the period/year		32,796		(31,119)		(44,141)
Items that may be reclassified subsequently   to profit or loss:
Gain/(Loss) on unrealized cash flow hedges		14,565		(34,440)		(14,849)
Hedging loss reclassified to profit or loss		2,702		15,425		27,417
		17,267		(19,015)		12,568
Tax (expenses)/credit relating to   components of other comprehensive loss		(5,180)		5,704		(3,770)
Other comprehensive income/(loss)		12,087		(13,311)		8,798
Total comprehensive income/(loss) for the     period/year		44,883		(44,430)		(35,343)

 

 

 

 

 

 

Condensed Consolidated Statement of Financial Position as at 30 June 2025

 

		30 June 2025		30 June 2024		31 December 2024
		Unaudited		Unaudited		Audited
	Notes	USD'000		USD'000		USD'000
Assets
Non-current assets
Intangible exploration assets	9	92,172		80,440		91,323
Oil and gas properties	10	455,673		480,189		422,239
Plant and equipment	10	10,400		10,508		10,591
Right-of-use assets	10	10,655		22,462		16,111
Investment in associate	11	-		25,007		19,544
Other receivables	12	281,426		262,493		274,124
Derivative financial instruments	21	1,058		-		-
Deferred tax assets		44,915		45,678		44,898
Cash and cash equivalents	13	636		1,356		888
Total non-current assets		896,935		928,133		879,718
Current assets
Inventories		29,930		56,243		44,602
Trade and other receivables	12	117,570		33,354		55,044
Derivative financial instruments	21	8,591		-		-
Tax recoverable		7,850		4,801		13,863
Cash and cash equivalents	13	58,406		129,513		94,338
Total current assets		222,347		223,911		207,847
Total assets		1,119,282		1,152,044		1,087,565
Equity and liabilities
Equity
Capital and reserves
Share capital	14	457		456		457
Share premium account	14	52,176		51,827		52,176
Merger reserve	15	146,270		146,270		146,270
Share-based payments reserve		28,048		27,889		27,730
Capital redemption reserve	16	24		24		24
Hedging reserve	17	6,754		(27,442)		(5,333)
Accumulated losses		(169,694)		(189,468)		(202,490)
Total equity		64,035		9,556		18,834
		30 June 2025 Unaudited		30 June 2024 Unaudited Reclassified*		31 December 2024 Audited
	Notes	USD'000		USD'000		USD'000
Non-current liabilities
Provisions	18	681,336		682,915		664,951
Borrowings	19	56,952		148,787*		122,978
Lease liabilities		922		10,353		5,308
Other payables	20	17,282		17,337		17,282
Derivative financial instruments	21	-		5,897		-
Deferred tax liabilities		61,414		71,556		59,620
Total non-current liabilities		817,906		936,845		870,139
Current liabilities
Borrowings	19	110,605		50,177*		77,212
Lease liabilities		10,146		14,192		12,243
Trade and other payables	20	105,441		90,839*		92,793
Derivative financial instruments	21	-		33,304*		7,618
Warrants liability	22	59		2,541		931
Provisions	18	5,549		11,994		5,542
Tax liabilities		5,541		2,596		2,253
Total current liabilities		237,341		205,643		198,592
Total liabilities		1,055,247		1,142,488		1,068,731
Total equity and liabilities		1,119,282		1,152,044		1,087,565

 

 

 

*US$20.3 million of borrowings reported as at 30 June 2024 has been reclassified from non-current to current as disclosed in Note 19. US$2.5 million of derivative financial liabilities instruments as at 30 June 2024 has been reclassified to trade and other payables as disclosed in Note 20 and Note 21.