2024 Full Year Results

 

Delivering to expectations, increasing resilience, guidance maintained

 

20 May 2025-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 2024.  

 

The Company will host a webcast at 1:00 p.m. UK time today, details of which can be found in the announcement below.

 

2024 operational performance demonstrates benefit of diversified portfolio

l Over 10 million manhours worked without a lost-time injury (LTI) across the Group's Indonesia and Malaysia operations.

l Delivered record annual production of 18,696 boe/d in 2024 (+35% year-on-year).

l Successful completion and start-up of the Akatara field, further diversifying the Group's production base, with gas sales commencing in July 2024 and the contractual performance test completing in December 2024.

l 10% reduction in adjusted unit operating costs in 2024 to US$33.68/boe (2023: US$37.24/boe)

l Independently audited 1P reserves by ERCE of 48.6 mmboe at year-end 2024, with a 1P reserves replacement ratio of more than 200%, greatly increasing the Group's resilience.

l Independently audited 2P reserves by ERCE of 68.3 mmboe at year-end 2024, resulting in a 2P reserves replacement ratio of 104% and a 10-year 2P reserve life, based on 2024 production

l Year-end 2024 2C resources increased by 19% year-on-year to 125.7 mmboe, or 18 years resource life based on 2024 production. Approximately 75% of the 2C resource base relates to the significant resource contained in the Group's gas discoveries offshore Vietnam.

 

Stable and resilient financial position

l 2024 revenues increased by 28% year-on-year to US$395.0 million (2023: US$309.2 million)

l Adjusted EBITDAX for 2024 of US$127.9 million, a 41% increase year-on-year, driven primarily the increase in revenues.

l Operating cash flow pre working capital for 2024 of US$70.5 million, a 93% increase on 2023 (US$36.5 million)

l Net debt of US$104.8 million at 31 December 2024 (31 December 2023: US$3.6 million net debt) has reduced to US$54.2 million at 30 April 2025, reflecting c.US$112.5 million of consolidated Group cash balances and US$167.0 million of debt drawn under the Group's reserve-based lending facility (RBL Facility).

l Signed a US$30 million working capital facility with a 31 December 2026 maturity. The working capital facility will be used for general corporate purposes, providing additional liquidity to the Group, if required.

l Available liquidity of US$142.5 million at 30 April 2025, including the undrawn working capital facility referenced above.

l Approximately 1.7 mmbbls of hedges in place covering the nine months ending 30 September 2025 at a weighted average hedge price of US$69.07/bbl.

l Certain of Jadestone's shareholders have requested that the Company seek authority to repurchase shares at the 2025 AGM on 20 June 2025.

 

Current trading and outlook - a strong start to 2025

l Strong portfolio performance year-to-date 2025, with production for the first four months of 2025 averaging 20,830 boe/d, a 22% increase year-on-year and an annual record for this period.

¡  Akatara has delivered robust performance year-to-date in 2025, with gross production averaging approximately 6,200 boe/d and 96% facilities uptime, both ahead of plan.

l All guidance metrics unchanged:

¡  2025 average production of 18-21,000 boe/d (post Sinphuhorm sale).

¡  2025 operating costs of US$250-300 million.

¡  2025 capital expenditure of US$75-95 million.

¡  2025-2027 free cash flow (pre debt servicing) guidance[1] of US$270-360 million.

l Active portfolio management with the sale of the Group's non-operated Thailand assets in April 2025 for an upfront consideration of US$39.4 million and contingent payments of US$3.5 million.

 

l Submission of the field development plan for the commercialization of the Nam Du/U Minh (NDUM) discoveries offshore southwest Vietnam to Petrovietnam, commencing the regulatory approval process.

l Skua-11ST well operations ongoing, to accelerate recovery of reserves from the Skua structure and extending the economic life of the Montara field by one year. Results expected in June 2025.

l Debottlenecking project at Akatara progressing, accelerating the commercialization of up 3.5 mmboe of reserves.

l In line with previous announcements, Jadestone has been reviewing its organizational and cost structure, with the aim of ensuring that the Group is run as efficiently as possible and enhancing its resilience to oil price cycles, while maintaining the highest safety standards. As part of this review, the Group will reduce the headcount of its Australian onshore office in Perth by approximately 25%. The targeted headcount reductions do not impact the Group's offshore Australia workforce. Jadestone's Australian asset portfolio remains a core focus for the Group and its growth ambitions.

l The Group continues to explore strategic acquisition opportunities to drive value and deliver scalable growth.

 

Dr. Adel Chaouch, Executive Chairman, commented:

 

"We closed 2024 on a very positive note, with the notable achievements of safely bringing Akatara onstream and doubling our interest in CWLH both contributing to our record production for the year, reducing unit opex and enhancing the resilience of the Group.

 

Jadestone's refreshed and reinvigorated management team is delivering on its promises.  We have seen a strong performance from our diverse portfolio so far in 2025, delivering record production for the first four months of the year and importantly, in line with guidance.  Our focus on operational excellence and maintaining high uptime levels across the portfolio is paying off, providing confidence for our shareholders in our full year guidance and targets, which are reiterated today.  In particular, we are very pleased at the initial performance of the Akatara field, where uptime and production early in 2025 has been ahead of plan, and we are confident that the cash flows and value from this asset will be the foundation of Jadestone's success for years to come.

 

Our operational progress is being delivered against a backdrop of enhanced macroeconomic uncertainty. Greater asset diversification due to successful growth, the onset of fixed price gas production from Akatara, our near-term oil price hedges and the premium to Brent for our oil sales means we are well-placed to weather oil price volatility.  We are also taking action to make Jadestone a more resilient business to oil price cycles, by targeting reductions in both operating costs and overheads.  We have strengthened the balance sheet with net debt reduced by approximately half in the first four months of 2025 and we have put in place a new working capital facility, resulting in liquidity at the end of April of US$142.5 million - a strong position from which to continue executing our 2025 activity program.

 

Jadestone has a rare and compelling investment proposition.  We have the skillset that covers both mid-life oil assets and greenfield gas developments, and a significant presence and platform to operate in three of the top five upstream producing countries in the Asia-Pacific region.  We continue to actively look for opportunities to achieve the scale which is increasingly important in the oil and gas sector, but we will only allocate capital in a way that will be accretive to shareholders."

 

Dr. Adel Chaouch

 

EXECUTIVE CHAIRMAN

 

 

2024 SUMMARY

 

US$'000 except where indicated	2024	2023
Total hours worked lost-time injury free (million)	4.93	4.55
Total recordable injury rate	2.51	0.86
Proven plus Probable Reserves (mmboe) - 31 December	68.3	68.0
Sales volume, total liquids and gas, barrels of oil equivalent (boes)	5,284,718	3,862,742
Production, boe/day1	18,696	13,813
Realized oil price per barrel of oil equivalent (US$/boe)2	85.21	87.34
Realized gas price per thousand standard cubic feet (US$/mcf)	3.91	1.53
Revenue3	395,036	309,200
Production costs	(276,969)	(232,772)
Impairment of oil and gas properties	-	(29,681)
Adjusted unit operating costs per barrel of oil equivalent (US$/boe)4	33.68	37.24
Adjusted EBITDAX4	127,895	90,647
(Loss)/Profit after tax	(44,141)	(91,274)
(Loss)/Earnings per ordinary share: basic & diluted (US$)	(0.08)	(0.18)
Operating cash flows before movement in working capital	70,526	36,499
Capital expenditure	74,459	115,882
Net (debt)/cash4 at 31 December	(104,774)	(3,596)

 

Operational and financial summary

 

·    Proven and Probable (2P) reserves at 31 December 2024 increased slightly year-on-year to 68.3 mmboe (2023: 68.0 mmboe),  driven by 6.7 mmboe of new reserves associated with the acquisition of a further 16.67% stake in the CWLH fields and minor upward revisions at Akatara and Sinphuhorm offsetting production in the year of 6.8 mmboe. Total 2P reserve additions of 7.1 mmboe during 2024 resulted in a 104% 2P reserve replacement ratio for the year.

·    Production rose 35% year-on-year to a record 18,696 boe/d (2023: 13,813 boe/d), primarily due to the CWLH 2 acquisition (+1,816 bbls/d), a full year of Montara production (+1,607 bbls/d) and commencement of production at Akatara (+977 boe/d).

·    Total sales volume of oil, gas, LPG and condensate in 2024 increased by 36% to 5.3 mmboe (2023: 3.9 mmboe), reflecting the increase in production.

·    Total revenue increased by 28% to US$395.0 million (2023: US$309.2 million) due to higher sales volumes, slightly offset by a lower realized oil price. Total 2024 revenue includes a hedging loss of US$27.4 million (2023: US$10.3 million) from commodity swap contracts associated with the RBL Facility.

·    The average realized oil price for the year before hedging was US$85.21/bbl in 2024 (2022: US$87.34/bbl). The average realized price premium for 2024 was US$3.76/bbl (2023: US$5.58/bbl). The lower premium year-on-year reflects a shift in the weighting of sales, with a greater proportion of CWLH crude and lower proportion of Stag crude in 2024 compared to 2023.

·    Reported production costs totalled US$277.0 million in 2024, a 19% increase from US$232.8 million in 2022. The majority (US$30.7 million) of the increase is explained by the (non-cash) change in lifting and inventory movements year-on-year.

¡  2024 adjusted unit operating costs³ of US$33.68/boe represented a 10% decrease over the prior year (2023: US$37.24/boe) primarily due to lower operating cost production at CWLH and Akatara added to the production mix during the year.

·    Impairment of oil and gas properties was nil in 2024, compared to US$29.7 million in 2023 due to impairments at Stag and non-producing assets offshore Malaysia.

·    Adjusted EBITDAX for 2024 increased by 41.2% to US$127.9 million, up from US$90.6 million in 2023, driven by the factors set out above.

·    2024 loss after tax of US$44.1 million (2023: US$91.3 million loss after tax), driven by the factors set out above

·    2024 operating cash flow before movements in working capital of US$70.5 million, a increase of 93% compared to 2023 (US$36.5 million).

·    2024 capital expenditure of US$74.5 million reduced 36% year-on-year (2023: US$115.9 million), primarily due to the completion of the Akatara development project.

·    Net debt of US$105.0 million at 2024 year-end (2023 year-end: US$3.6 million), reflected a full drawdown of US$200.0 million from the RBL Facility and total cash and cash equivalents of US$95.0 million.

¡   The scheduled RBL March 2025 redetermination concluded on 2 April 2025, resulting in a borrowing base of US$167.0 million for the six month period ending 30 September 2025, which is currently fully drawn.

 

¹ 2024 Production includes Sinphuhorm gas and condensate production in accordance with Petroleum Resource Management Systems guidelines, 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 associated with Sinphuhorm are excluded from the Group's financial results.

²  Realized oil price represents the actual selling price inclusive of premiums or discounts to Brent.

³ Revenue in 2024 of US$395.0 million (2023: US$309.2million) includes a hedging loss of US$27.4 million (2023: US$10.3 million) from the commodity swap contracts associated with the RBL Facility.

⁴ Adjusted unit operating costs per boe, adjusted EBITDAX and net debt/cash are non-IFRS measures and are explained in further detail in the Non-IFRS Measures section of this document.

 

 

Enquiries 

 

Jadestone Energy plc.
Phil Corbett, Head of Investor Relations	+44 7713 687 467 (UK)
	[email protected]
Stifel Nicolaus Europe Limited (Nomad, Joint Broker)	+44 (0) 20 7710 7600 (UK)
Callum Stewart / Jason Grossman / Ashton Clanfield
Peel Hunt LLP (Joint Broker)	+44 (0) 20 7418 8900 (UK)
Richard Crichton / David McKeown / Georgia Langoulant
Camarco (Public Relations Advisor)	+44 (0) 203 757 4980 (UK)
Billy Clegg / Georgia Edmonds / Poppy Hawkins	[email protected]

 

Full-year 2024 presentation webcast

The Company will host an investor and analyst presentation at 1:00 p.m. (UK time) on Tuesday, 20 May 2025, including a question-and-answer session, accessible through the link below:

 

Webcast link: https://www.investis-live.com/jadestone-energy/681de341f8132e000ea6c65a/nehyi    

Event title: Jadestone Energy Full-Year 2024 Results

Time: 1:00 p.m. (UK time)

Date: 20 May 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): +44 800 358 1035

Global Dial-In Details: https://www.netroadshow.com/events/global-numbers?confId=70236  

Access Code: 722579

 

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.

 

HSE performance

 

The Group's priority remains the health and safety of its staff, contractors and communities in which it operates, along with ensuring that any negative environmental impacts from operations are minimized. 

 

2024 saw a significant increase in work hours, reaching 5.41 million (2023: 4.64 million), largely driven by intensified commissioning efforts at the Akatara Gas Processing Facility (AGPF) in Indonesia. Lagging metrics were met with zero life altering events, zero major environmental events and one LTI, at a rate of 0.18 / million manhours, exceeding industry safety benchmarks (the 2024 target was less than the 2023 IOGP average of 0.242). A lost-time injury occurred at Montara when a worker injured his shoulder.

 

The Group experienced four high potential incidents in 2024, a reduction of 33% from 2023. Two were related to dropped objects and there were two electrical near misses.  Dropped objects were a focus in 2024, resulting in a 60% reduction year-on-year. Jadestone continues to learn from near misses and share learnings, both internally and externally.

 

At the AGPF, construction was largely completed at the beginning of the year, with the focus in first year half on equipment testing, pre-commissioning, and commissioning, along with a successful workover campaign on five existing wells supplying gas to the facility. On 18 June 2024, mechanical completion was achieved at the plant, marking the start of final commissioning and production ramp-up. First export gas was achieved on 31 July 2024 and the 72-hour performance test was completed on 9 December 2024. Completion of the performance test marked the conclusion of the commissioning phase at Akatara, with responsibility for day-to-day operations transitioning from the EPCI contractor to Jadestone. During this busy period, Jadestone's team maintained safe operations, logging over four million hours worked without an LTI.

 

One Tier 1 process safety event was recorded at the AGPF, where a gas detector was activated due to a crack in the small bore piping on an export compressor. The compressor was shut down, isolated and depressurized and an investigation revealed that additional bracing was required to bring vibration within acceptable levels. After additional bracing was installed, post start-up checks confirmed vibration was within acceptable levels.

 

Net Zero interim targets

Jadestone's strategy for maximizing reserves from existing producing oil and gas fields explicitly precludes frontier exploration and new greenfield development, a position that is informed by the IEA's Net Zero Emissions by 2050 Scenario. The Group is well positioned to benefit from the energy transition as a responsible steward of mid-life assets, committed to upholding climate targets and achieving its Net Zero interim reduction targets.

 

The Group is committed to reduce Scope 1 and 2 GHG emissions (in tonnes of CO₂-e) from its operated assets by 20% by 2026 and by 45% by 2030, relative to 2021 levels. This commitment applies to emissions from the Group's existing operated assets. Jadestone will make best endeavours to retain GHG reduction levels when integrating future acquisitions into the interim targets, subject to reviews of GHG abatement opportunities.

The Group's gross Scope 1 GHG emissions during 2024 amounted to 587 kilo tonnes CO₂-e (2023: 480 kilo tonnes CO₂-e^[2]). The year-on-year increase reflects several factors, including significantly higher uptime at Montara during 2024 and the addition of the Akatara field to Jadestone's producing portfolio. Jadestone does not consume any purchased electricity at any of its operated sites. Its indirect, Scope 2, GHG emissions from the consumption of purchased electricity at its offices and warehouses accounts for less than 1% of Scope 1 and 2 GHG emissions combined.

 

Jadestone intends that its interim GHG emissions reduction targets will be achieved through a combination of measures, ranging from operational GHG reductions, including minimizing flaring, as well as reliance on carbon credits within the regulatory schemes of Jadestone regions. For further details, refer to Jadestone's 2024 Annual Report as well as the Sustainability Report, which will be published by the end of May 2025.

 

Governance

 

The Board gained a variety of skillsets and experience throughout 2024 and into early 2025 with the longer-term objective to ensure that the Board is sized appropriate to the Company's scale and ambition, while maintaining appropriate capabilities and adhering to corporate governance standards.

 

Joanne Williams was appointed on 25 January 2024 as an independent Non-Executive Director. Dr. Adel Chaouch was appointed to the Board on 25 March 2024 as an independent Non-Executive Director and elected as Chair of the Board on 27 March 2024 after Dennis McShane stepped down. Additionally, both Lisa Stewart and Robert Lambert stepped down from the Board effective 25 March 2024.

 

Linda Beal was appointed as an independent Non-Executive Director and Audit Committee Chair on 9 May 2024.  Iain McLaren did not seek re-election at the Company's AGM and stepped down from the Board on 13 June 2024.

 

Andrew Fairclough was appointed as Executive Director and Chief Financial Officer (CFO) on 29 October 2024 replacing the Group's former CFO, Bert-Jaap Dijkstra, who stepped down as CFO and Executive Director on the same date.

 

During the second half of 2024, the Board evaluated the performance of the Group and its management team, comparing actual outcomes against targets and the resulting share price performance. After consulting material shareholders of the Company, the Board subsequently decided that a change in Jadestone's management team was required to best position the Group for future success. As a result, Paul Blakeley stepped down as Executive Director, President, and CEO effective 5 December 2024. The Board decided that Dr. Chaouch, with his extensive upstream experience and management roles, would be best placed to provide leadership, through combining the CEO role with his existing duties as Chairman of the Board. Dr. Chaouch's appointment as Executive Chairman is on a fixed-term basis, with appropriate incentives to ensure alignment with shareholders and drive the success of the Group. At the same time and in alignment with the QCA Code guidance and good governance practice, Linda Beal was appointed as Senior Independent Director.

 

Given the management changes highlighted above, and while a search for a Chief Executive Officer was progressed, the Board concluded that Joanne Williams had the experience and skills to support the management team through this period. She agreed to take an operational role as Chief Operating Officer on a fixed term basis. After taking external advice, the Non-Executive Directors determined that Joanne Williams would remain an independent Non-Executive Director while performing her management role during this period.

 

On 16 January 2025, David Mendelson was appointed as an independent Non-Executive Director and Cedric Fontenit stepped down as an independent Non-Executive Director effective 20 January 2025.

 

The Board is progressing the appointment of an appropriate candidate as CEO.

OPERATIONAL REVIEW

 

Producing Assets

 

Australia

 

Montara Project (100% working interest, operated)

 

The Montara fields averaged 5,262 bbls/d in 2024, compared to 3,655 bbls/d in 2023. The year-on-year increase is primarily explained by higher uptime and availability of the Montara Venture FPSO in 2024, after Montara production was shut-in during early 2023 for repairs and maintenance activity on the FPSO's storage tanks. Montara production in the second half of 2024 also benefitted from the return to production of the H6 and Swift-2 wells, which had been offline due to mechanical issues.

 

Following the significant activity on the FPSO's oil storage tanks since 2022, the Montara Venture's storage capacity has now increased to over 600,000 barrels[3]. Increasing oil storage availability allowed for the temporary shuttle tanker offloading arrangement to be phased out during the fourth quarter of 2024, reducing transportation costs. The Group expects to resume the FOB sale of larger cargoes of Montara crude from mid-2025 onwards, further reducing lifting-related costs.

 

The Group's main capital activity during 2025 is the drilling of the Skua-11 sidetrack well (Skua-11ST), which commenced in April. This well has dual objectives of decommissioning the original Skua-11 well and drilling a sidetrack into the Skua structure up-dip of the original Skua-11 well path. Based on pre-drill expectations, a successful Skua-11ST well would accelerate recovery of reserves from the Skua structure and extend the economic life of the Montara Project by one year.

 

In total, seven cargoes totaling 1.9 mmbbls (2023: five cargoes of 1.2 mmbbls) were lifted from Montara in 2024, with an average realization of US$83.68/bbl (consisting of an average Brent price of US$80.20/bbl and average premium of US$3.48/bbl). This compares to an average realization of US$84.79/bbl in 2023 (Brent US$80.97/bbl and premium US$3.82/bbl).

 

CWLH (33.33% working interest, non-operated)

 

On 14 February 2024, the Group completed the acquisition of an additional 16.67% working interest in the Cossack, Wanaea, Lambert and Hermes oil fields offshore western Australia, doubling its working interest to 33.33%.

 

During 2024, Jadestone's net production from the CWLH fields averaged 3,711 bbls/d, compared to 1,896 bbls/d in 2023. The year-on-year change is primarily explained by the increase in the Group's working interest referenced above. However, the CWLH asset outperformed expectations in 2024 with average production 6% ahead of the Group's forecast, driven by better than expected reservoir performance.

 

Following engagement with the CWLH joint venture, total abandonment trust fund payments associated with the acquisition of the additional 16.67% interest were finalized at US$83.8 million, all of which was paid in 2024.

 

The Group lifted two cargoes of 1.3 mmbbls (2023: one cargo of 0.7 mmbbls) from CWLH in 2024 for an average realization of US$82.38/bbl (consisting of an average Brent price of US$83.20/bbl and an average discount of US$0.82/bbl). This compares to a realization of US$82.81/bbl in 2023 (Brent US$83.18/bbl and discount of US$0.37/bbl) for the one cargo lifted in 2023.

Stag (100% working interest, operator)

 

Stag field production averaged 2,006 bbls/d in 2024, compared to 2,671 bbls/d in 2023.

 

Production in 2023 benefited from the initial production impact of the Stag-50H and 51H wells drilled in November 2022. Stag field production in 2024 reflected the impact of weather-related downtime in the early part of the year, and mechanical issues in several wells which required workovers to restore output. Attempts to restore production from the Stag-48H well during 2024 and early 2025 were unsuccessful, with further activity on this well under review.

 

Several initiatives are currently underway to address the well reliability and uptime issues at Stag that have impacted production in recent years, with Stag production increasing during the first half of 2025 as a result. The Stag field's operating cost structure is also being reviewed to ensure that asset cash flows and the economic life of the field can be maximized.

 

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 0.7mmbbls in 2024 (2023: four cargoes totaling 1.0 mmbbls). Premiums for Stag crude have remained strong, with the average realization for 2024 sales of US$95.93/bbl (Brent US$82.18/bbl and premium US$13.75/bbl), compared to an average 2023 realization of US$94.16/bbl (Brent US$81.13/bbl and premium US$13.03/bbl).

 

Indonesia

 

Akatara (100% working interest[4], operator)

 

The Akatara field is located within the Lemang PSC onshore Sumatra in Indonesia. Akatara was previously developed as an oil field, prior to being redeveloped by Jadestone to commercialize gas, condensate and LPG reserves located in shallower zones.

 

Development activity at Akatara finished in the first half of 2024, culminating in a declaration of mechanical completion at the Akatara Gas Processing Facility in June 2024, and the introduction of reservoir gas from one of the five production wells, with condensate production also commencing at this point.

 

Commissioning of the facility continued during the second half of 2024, with facility uptime and production volumes steadily increasing as several commissioning issues were encountered and addressed.

 

The Akatara gas development successfully completed its formal EPCI contract performance test in December 2024. This required a continuous 72-hour test of the AGPF at full production rates, representing the daily contract quantity under the Akatara gas sales agreement and associated LPG and condensate production. This milestone marked the conclusion of the commissioning phase at Akatara, with responsibility for day-to-day operations at the AGPF transitioning from the EPCI contractor to Jadestone.

 

Akatara production, on an annual average basis, was 977 boe/d in 2024 (2023: nil). A total of 1.2 bcf of gas was sold in 2024 at an average price of US$5.97/mcf, with initial Akatara LPG and condensate sales totaling approximately 150,000 barrels, which were sold for a weighted average price of US$56.69/bbl.

 

Akatara performance in early 2025 has been ahead of expectations, with 96% AGPF uptime year-to-date and gross production averaging approximately 6,200 boe/d. The focus in 2025 is to implement a series of minor plant upgrades during the scheduled annual shut down in May 2025, which will enhance the overall resiliency of the AGPF.

 

The Group continues to progress its plans to increase the capacity of the AGPF through a debottlenecking project. It is now expected that the debottlenecking project will follow a phased approach, with an increase in AGPF capacity in mid-2025 through modifying and optimizing plant gas processing, with the remainder of the proposed increase in capacity coming in the second half of 2026 following engineering, procurement and installation of additional processing equipment. The phased approach will result in an earlier increase in plant capacity than previously expected, with lower upfront costs and is still expected to accelerate the production of 3.5 mmboe of reserves.

 

The HSE performance at Akatara has been highly impressive, with over eight 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 3,484 bbls/d net to Jadestone's working interest in 2024 (2023: 2,203 bbls/d). The year-on-year increase was due to the positive impact of the Group's infill drilling program on the East Belumut field in late 2023.

 

The Group is progressing plans for further infill drilling on the East Belumut field in 2026, focusing on the undrained southwestern area of the field discovered during the 2023 drilling campaign.

 

A total of 0.6 mmbbls (2023: 0.4 mmbbls) were lifted from the PM323 PSC during 2024, with an average realization of US$84.30/bbl (2023: US$86.99/bbl).

 

PM329 PSC (70% working interest, operator)

 

The PM329 PSC produced an average of 1,501 boe/d net to Jadestone's working interest in 2024, consisting of 1,024 bbls/d of oil and 2.9 mmcf/d of gas (2023: 2,085 boe/d, consisting of 1,461 bbls/d of oil and 3.7 mmcf/d of gas). The year-on-year decrease is due to natural decline.

 

A total of 0.3 mmbbls of oil (2023: 0.3 mmbls) were lifted from the PM329 PSC in 2024, with an average realization of US$83.89/bbl (2023: US$86.82/bbl). In addition, approximately 1.0 bcf of gas was sold at an average realization of US$1.60/mcf.

 

Puteri Cluster (100% working interest, operator)

 

In July 2024, Jadestone was awarded a 100% participating interest in the Puteri Cluster Production Sharing Contract (the Puteri Cluster PSC, previously referred to as the SFA Cluster PSC) offshore Peninsular Malaysia. The Puteri Cluster PSC covers an area of 348km² in shallow water offshore Peninsular Malaysia located adjacent to the Group's existing operated PM323 and PM329 PSCs and is surrounded by the PM428 PSC (see below).

 

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.

 

Jadestone currently estimates that the Puteri Cluster PSC contains approximately 15.4 mmbbls of gross 2C contingent resources. 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.

 

PM428 PSC (60% working interest, operator)

 

In January 2024, Jadestone was awarded a 60% operated interest in the PM428 PSC offshore Peninsular Malaysia. The PM428 PSC is adjacent to the PM323 and PM329 PSCs and surrounds the Puteri Cluster PSC (referenced above). The PM428 PSC 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

Thailand

 

Sinphuhorm (9.52% working interest, non-operated)

 

During 2024, the Sinphuhorm field produced an average of 1,755 boe/d (1,734 boe/d gas and 21bbls/d of condensate). Production for 2023 averaged 1,303 boe/d (expressed as an annual average from completion of the Sinphuhorm acquisition on 23 February 2023). The year-on-year increase in 2024 reflected the partial ownership in 2023, strong gas demand in northern Thailand in the second half of 2024, the successful commissioning of a booster compression project in 2024 and robust performance from recent infill wells.

 

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, instead recognizing dividend income when received from APICO LLC. Dividends of US$8.2 million were received in 2024 (2023: US$4.3 million).

 

On 16 April 2025, the Group announced that it had sold its Thailand interests 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.

 

Pre-production Assets

 

Vietnam

 

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

 

In January 2024, the Group announced that it had signed a Heads of Agreement (HoA) with Petrovietnam Gas Joint Stock Corporation for the Gas Sales and Purchase Agreement (GSPA) relating to the Nam Du and U Minh (NDUM) gas fields development, located in the Block 46/07 and Block 51 Production Sharing Contracts in shallow waters offshore southwest Vietnam.

 

Following signature of the HoA, the Group commenced detailed negotiations over a fully termed GSPA, which are currently well advanced. The HoA also allowed for the submission in March 2025 of an updated field development plan (FDP) for the NDUM fields, the approval of which is required before a final investment decision can be taken. The FDP specifies the development concept for the NDUM fields, associated capital and operating cost estimates, and a schedule to first gas.

 

The Block 46/07 PSC includes a commitment to drill an additional exploration well. In February 2024, Jadestone submitted an application to extend the commitment period and proposed that the well be incorporated into the Nam Du field development drilling program. As at 31 December 2024, the Field Development Plan (FDP) incorporating the commitment well, had not yet been submitted for approval.   The company has recognised a provision of US$10.0 million in respect of this obligation.  Subsequent to the year-end, the Company submitted the FDP on 18 March 2025.

 

The Group continues to work with Petrovietnam and other government entities to obtain a suspension of the relinquishment obligation for Block 51, which contains the Tho Chu discovery.

Reserves and resources

 

Total 2P Reserves1 (net, mmboe)
	Australia	Malaysia2	Indonesia2	Thailand3	Total Group
Opening balance, 1 January 2024	31.6	9.2	23.3	3.9	68.0
Acquisitions	6.7	-	-	-	6.7
Technical revisions	(0.2)	-	0.1	0.5	0.4
Production	(4.0)	(1.8)	(0.4)	(0.6)	(6.8)
Ending balance, 31 December 2024	34.1	7.4	23.0	3.8	68.3

 

As at 31 December 2024, the Group had 2P Reserves of 68.3 mmboe, a slight increase compared with 31 December 2023, after accounting for production in 2024. New 2P reserves of 6.7 mmboe were booked on the closing of an additional 16.67% interest in CWLH fields in February 2024. There were minor upward technical revisions at the Akatara field in Indonesia and Sinphuhorm in Thailand, with the latter due to higher forecast gas demand through to the end of license expiry in 2031. Collectively, these 7.1 mmboe of positive revisions were sufficient to offset production of 6.8 mmboe, representing 104% 2P reserve replacement during the year.

 

ERC Equipoise Limited independently evaluated the Group's year-end 2024 reserves.

 

Total 2C Contingent Resources4 (net, mmboe)
	Australia	Malaysia	Indonesia2	Thailand3	Vietnam2	Total Group
Opening balance, 1 January 2024	5.1	1.2	0.9	4.4	93.9	105.6
Acquisitions	5.5	-	-	-	-	5.5
Transfer to 2P reserves	-	-	-	-	-	-
Technical revisions	-	15.1	-	(0.4)	-	14.7
Ending balance, 31 December 2024	10.6	16.3	0.9	4.0	93.9	125.7

 

Group 2C resources as at 31 December 2024 are estimated at 125.7 mmboe, an increase of 19% year-on-year, mainly reflecting the addition of 2C resources associated with the Puteri Cluster PSC award during the year and the CWLH 2 acquisition in February 2024. Approximately 75%, or 93.9 mmboe, of the Group 2C resources at 31 December 2024 relates to the significant resource contained in the Group's gas discoveries offshore Vietnam.

¹ Proven and Probable Reserves for Jadestone's assets have been prepared in accordance with the June 2018 SPE/WPC/AAPG/ SPEE/SEG/SPWLA/EAGE Petroleum Resources Management System ("PRMS") as the standard for classification and reporting.

² Assumes oil equivalent conversion factor of 6,000 scf/boe.

³ Assumes oil equivalent conversion factor of 5,740 scf/boe. The Group disposed of its assets in Thailand on 16 April 2025 to a subsidiary of Thailand's national oil and gas company, PTTEP, for an initial consideration of US$39.4 million and contingent payments of US$3.5 million.

⁴ Contingent Resources based on Jadestone estimates as at 31 December 2024, except for Vietnam 2C resources which are based on ERCE Competent Person's Report effective 31 December 2017

 

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 2024.

 

US$'000 except where indicated	2024	2023
Production, boe/ day1	18,696	13,813
Oil and liquids sales, barrels of oil equivalent (boes) 2	4,764,875	3,634,991
Realized oil price per barrel of oil equivalent (US$/bbl)3	85.21	87.34
Gas sales, thousand standard cubic feet (mcf)	2,216,652	1,366,505
Realized gas price per thousand standard cubic feet (US$/mcf)	3.91	1.53
Sales volume for LPG and condensates, barrels (bbls)	150,401	-
Realized LPG and condensate price per barrel (US$/bbl)3	56.69	-
Revenue4	395,036	309,200
Production costs	(276,969)	(232,772)
Adjusted unit operating costs per barrel of oil equivalent (US$/boe)5	33.68	37.24
Adjusted EBITDAX5	127,895	90,647
Unit depletion, depreciation and amortization (US$/boe)	12.45	14.14
Impairment of assets	-	(29,681)
(Loss) before tax	(43,435)	(102,766)
(Loss) after tax	(44,141)	(91,274)
(Loss) per ordinary share: basic and diluted (US$)	(0.08)	(0.18)
Operating cash flows before movement in working capital	70,526	36,499
Capital expenditure	74,459	115,882
Net (debt)/cash  at 31 December	(104,964)	(3,596)

 

 

Benchmark commodity price and realized price

 

The actual average realized price in 2024 decreased by 2% to US$85.21/bbl, from US$87.34/bbl in 2023. The benchmark Dated Brent price remained virtually flat at US$81.45/bbl in 2024, compared to US$81.76/bbl in 2023. The reduction in the realized price was predominately due to the decline in the average premium to US$3.76/bbl in 2024, compared to US$5.58/bbl in 2023. The lower premium reflected a change in the composition of sale volumes, with CWLH crude comprising a higher proportion of sale volumes in 2024, compared to higher premium Stag barrels in 2023. The Stag premium in 2024 averaged US$13.75/bbl (2023: 13.03/bbl), compared to the CWLH average discount at US$0.82/bbl (2023: average discount at US$0.37/bbl).

¹ Production includes Sinphuhorm gas and condensate production in accordance with Petroleum Resource Management Systems guidelines, non-IFRS measure. However, in accordance with IAS 28 the investment is accounted for as an associated undertaking and the Group only recognizes dividends received. Accordingly, the revenue and production costs from the Sinphuhorm Asset are excluded from the Group's financial results.

² Sales volumes include oil, condensate and LPG.

³ Realized oil price represents the actual selling price inclusive of premiums or discounts.

⁴ Revenue in 2024 and 2023 includes a hedging charge of US$27.4 million and U$10.3 million respectively from the commodity swap contracts associated with the RBL Facility.

⁵ Adjusted unit operating cost per boe, adjusted EBITDAX and net cash are non-IFRS measures and are explained in further detail in the Non-IFRS Measures section in this document.

 

Production and liftings

 

Production for 2024 was 18,696 boe/d, an increase of 4,883 boe/d compared to 13,813 boe/d in 2023. This overall increase was driven by the following key factors:

·      The acquisition of a further 16.67% interest in CWLH increased production to 3,711 bbls/d in 2024 compared to 1,896 bbls/d in 2023;

·      Montara achieved a full year production in 2024 of 5,262 bbls/d, compared to 2023 of 3,655 bbls/d, after production resumed in March 2023 following repairs to the Montara Venture FPSO's tanks;

·      Akatara completed commissioning and start-up activities with first commercial production achieved on 31 July 2024 at annual average rate of 977 boe/d;

·      Production from the PenMal Assets increased by 697 boe/d in 2024 to 4,985 boe/d (2023: 4,288 boe/d) due to the successful infill drilling campaign at the end of 2023 on the PM323 PSC; and

·      Sinphuhorm production increased year-on-year in 2024  to 1,755 boe/d (2023: 1,303 boe/d) reflecting a full-year of asset ownership, commissioning of a booster compressor at the field and strong gas demand in northern Thailand.

 

The increase was partly offset by:

·      Production at Stag decreased by 665 bbls/d in 2024 to 2,006 bbls/d (2023: 2,671 bbls/d) due to extended downtime caused by adverse weather conditions and downhole mechanical issues in wells which required workovers.

 

Throughout the year, the Group completed 21 crude liftings compared to 19 in 2023, leading to oil sales totalling 4.8 mmbbls, up from 3.6 mmbbls in 2023. Condensate and liquefied petroleum gas (LPG) produced from Akatara lifted a combined 0.15 mmbbls starting the second half of 2024 upon commencement of of Akatara field (2023: nil)

 

The Group recorded a sale of 1,047.1 mmcf and 1,169.6 mmcf of gas from the PenMal Assets and Akatara respectively in 2024, compared to 1,366.5 mmcf of gas in 2023 from the PenMal Assets.

 

Revenue

 

The Group generated net revenue after hedging effects of US$395.0 million in 2024, an increase of 28% compared to 2023 of US$309.2 million. The increase of US$85.8 million was predominately due to:

·      An increase in lifted volumes by 1.1 mmbbls year-on-year resulting in increased revenue of US$96.3 million; and

·      Akatara generated US$14.9 million after first gas on 31 July 2024, consisting of US$6.4 million from gas sales, US$4.3million of LPG and US$4.2 million of condensate sales.

 

The increase was partly offset by:

·      Hedging losses increased US$17.1 million to US$27.4 million in 2024, based on a weighted average hedging price of US$69.07/bbl from the commodity swap contracts associated with the RBL Facility compared to loss of US$10.3 million in 2023 (the hedging contracts commenced in October 2023);

·      Lower average realized price in 2024 of US$85.21/bbl (2023: US$87.34/bbl), resulting in a revenue decrease of US$7.7 million; and

·      Revenue generated in 2024 from PM329 gas sales decreased US$0.5 million to US$1.6 million in 2024 compared to US$2.1 million in 2023.

Production costs

 

Production costs increased by 19% in 2024 to US$277.0 million, from US$232.8 million in 2023, amounting to an increase of US$44.2 million.

 

		2024 US$'000		2023 US$'000		Variance US$'000
Operating costs		111,736		98,723		13,013
Workovers		20,797		17,562		3,235
Logistics		26,928		34,109		(7,181)
Repairs and maintenance		70,304		55,572		14,732
Tariffs and transportation costs		8,451		7,502		949
Supplementary payments and royalties		17,342		16,056		1,286
Decommissioning expenses		-		12,545		(12,545)
Underlift, (overlift) and crude inventories movement		21,411		(9,297)		30,708
		276,969		232,772		44,197

The year-on-year increase was predominately due to the following factors:

 

·     Operating costs increased by US$13.0 million to US$111.7 million in 2024, compared to US$98.7 million in 2023, due to several factors. The increase includes US$15.4 million for CWLH due to the additional interest acquired in February 2024. Operating costs at the PenMal Assets were higher by US$4.2 million due to inventory adjustments. Akatara incurred US$4.8 million of operating costs following first gas in July 2024. These increases were offset by reductions at Montara and Stag which decreased by US$11.4 million, due to reduced costs for crude tanker hire rates, lower diesel consumption by US$4.4 million and the non-recurring waste disposal cost for NORMs (naturally occurring radioactive material) was US$1.0 million lower in 2024.

 

·       Workover costs increased by US$3.2 million to US$20.8 million in 2024, compared to US$17.6 million in 2023. This rise was primarily driven by complex well-integrity repairs at Stag, which cost US$2.2 million more than the previous year. Additionally, the PenMal Assets incurred US$2.9 million in workover costs during 2024 for well integrity and performance improvements.

 

·       Logistical costs decreased by US$7.2 million to US$26.9 million in 2024 from US$34.1 million, primarily due to a US$4.9 million reduction at Montara following the unavailability of helicopters, which led to lower standing charges, and a US$3.0 million decrease at PenMal's Puteri Cluster due to minimal offshore activity after the demobilization of the FPSO. These reductions were partially offset by a US$0.6 million increase at Stag, where multiple cyclone events in 2024 required more frequent use of support vessels and helicopters compared to 2023.

 

·       Repairs and maintenance (R&M) increased by US$14.7 million, rising to US$70.3 million in 2024 from US$55.6 million in 2023. Akatara recorded US$6.0 million R&M following the start of commercial production. Montara's costs rose by US$3.3 million due to an ROV campaign and subsea inspections, while the PenMal Assets incurred an additional US$3.0 million from engine overhauls on producing assets and topsides flushing and pipeline preservation works at the Puteri Cluster facilities. Stag saw a net increase of US$2.4 million for one-off remedial works on the CALM buoy and export pipeline.

 

·       Supplementary payments and royalties increased by US$1.3 million in 2024 due to higher production-based royalties at Montara, CWLH and Akatara. This was offset with a decrease at PenMal Assets.

 

·      The PenMal Assets incurred a one-off decommissioning expense of US$12.5 million in 2023, related to decommissioning activities on the Bunga Kertas FPSO at the PNLP Assets.

 

·     Underlift, overlift and crude inventories movement (non-cash) increased US$30.7 million driven by the second acquisition of 16.67% of the CWLH assets in February 2024. The acquired underlift was valued at US$40.5 million and was included in inventory movements until it was sold as part of the March 2024 lifting. Apart from the CWLH underlift, the net year-on-year movement generated a credit of US$9.8 million reflecting a decrease in inventory movements across the asset portfolio.

 

The adjusted unit operating cost per barrel of oil equivalent in 2024 was US$33.68/boe (2023: US$37.24/boe) (please refer to the Non-IFRS measures section later in this document). The decrease was primarily due to the change in the production mix, principally the lower operating costs at Akatara and CWLH.

 

Depletion, depreciation and amortization (DD&A)

 

DD&A charges increased to US$91.4 million in 2024, up from US$76.1 million in the prior year. The rise was primarily driven by higher production at Montara, which accounted for an additional US$16.8 million, and the commencement of production at Akatara, contributing US$2.6 million. These uplifts were partially offset by a US$5.6 million reduction at Stag due to lower output, and a US$1.6 million decrease at CWLH, attributed to the application of IFRS 3 (Business Combinations) purchase price accounting following the increase in the Group's interest in February 2024.

 

In 2024, the Group's right-of-use asset depreciation increased by US$0.9 million to US$16.2 million compared to US$15.3 million in 2023. This increase was primarily attributable to the full-year depreciation effect of leases that were either signed or renewed during 2023.

 

There was a decrease in the overall depletion cost on a unit basis, reducing to US$12.45/boe in 2024 from US$14.14/boe in 2023. This reduction was mainly due to the reclassification of Akatara's capitalized development costs to production assets for depletion, which resulted in a relatively low unit depletion cost of US$3.66/boe for Akatara in 2024.

 

Staff costs

 

Total staff costs in 2024 were US$65.0 million (2023: US$56.2 million), comprising US$30.6 million (2023: US$26.0 million) in relation to offshore employees (recorded under production costs), and US$34.4 million (2023: US$30.2 million) for office-based employees. The average number of employees during the year was 422 (2023: 409), with the additional staff costs and headcount year-on-year mainly due to Akatara commencing production and onshore support in Australia. During the year, there was compensation for loss of office amounting to US$2.3 million, plus, US$0.2 million of payroll tax for the departure of the former CEO, Mr A. Paul Blakeley. These amounts were accrued in 2024 and paid in 2025.

 

Other expenses and allowance for expected credit losses

 

		2024 US$'000		2023 US$'000		Variance US$'000
Non-recurring corporate costs		1,397		3,602		(2,205)
Recurring corporate costs and other expenses		17,009		11,742		5,267
Allowance for expected credit losses		457		-		457
Allowance for slow moving inventories		1,670		655		1,015
Assets written off		1,775		5,114		(3,339)
Net foreign exchange loss		2,008		1,728		280
		24,316		22,841		1,475

 

Other expenses increased US$1.5 million in 2024 to US$24.3 million (2023: US$22.8 million), predominately due to:

 

·      Non-recurring corporate costs fell by US$2.2 million to US$1.4 million in 2024. This reduction included US$0.9 million of business development fees, and US$0.5 million of financing fees. The 2023 total was US$3.6 million, with US$2.2 million for business development, US$0.8 million for reorganization costs, US$0.4 million for an equity fundraising and US$0.2 million for financing fees.

 

·      Recurring corporate costs increased by US$5.3 million to US$17.0 million in 2024 (2023: US$11.7 million). While general administrative expenses for office operations, professional services and travel remained consistent year-over-year, the increase was due to a full-year of dividend based royalties at Sinphuhorm, withholding taxes and higher professional fees related to executive recruitment, consulting fees and other expenses.

 

·      The allowance for expected credit losses in 2024 of US$0.5 million (2023: Nil) represents a specific bad debt provision created against a customer during the year.

 

·      The allowance for slow-moving materials and spares more than doubled to US$1.6 million in 2024 from US$0.7 million in 2023, due to an increase in slow-moving inventory related to supplies.

 

·      Assets written off decreased by US$3.3 million in 2024, with total write-offs of US$1.8 million compared to US$5.1 million in 2023. The 2024 write-offs mainly related to US$1.8 million for obsolete Montara materials and spares. In contrast, the 2023 write-offs were higher, including US$3.1 million from the cancellation of the Skua-12 well project and US$2.1 million for obsolete inventory.

 

·      Net foreign exchange loss of US$2.0 million in 2024 (2023: US$1.7 million) mainly arising from the Group's receivables denominated in Malaysian Ringgit ("MYR") due to the volatility of MYR against USD towards the end of 2024.

 

Finance costs

 

Finance costs in 2024 were US$45.1 million (2023: US$41.8 million), an increase of US$3.3 million predominately due to:

 

·      Interest fees for the RBL Facility increased by US$8.3 million to US$16.4 million (2023: US$8.1 million). The increase reflects higher borrowings and full year of interest and expenses compared to a partial period of expense incurred in 2023 (the RBL Facility was signed in May 2023).

 

·      Accretion fees for the Asset Retirement Obligation (ARO) increased by US$2.4 million to US$22.6 million (2023: US$20.2 million), predominantly due to the additional ARO recognized for CWLH working interest acquired in 2024;

The above increased was offset by:

 

·    The warrant reserve generated a decrease of US$3.5 million in 2024, as the reserve was created during the 2023 equity raise,

 resulting in a US$3.5 million charge in that year. In 2024, there was no movement on the reserve. The revaluation of the

 warrant liability is included in Other Financial Gains.

 

·      Upfront fees and interest associated with the working capital facility and financing facilities decreased by US$1.3 million to US$2.4 million, compared to US$3.7 million in 2023.

 

·      The accretion expense for Akatara long-term VAT receivables decreased by US$1.0 million to US$0.2 million in 2024 compared to US$1.2 million in 2023.

       

·      Changes in fair value of contingent payments in 2024 of US$0.1 million, a US$0.8 million decrease compared to US$0.9 million in 2023.

 

·      RBL commitment fees in 2024 of US$0.1 million, a US$0.3 million decrease compared to US$0.4 million in 2023.

 

Other income

 

The Group generated US$29.6 million of other income in 2024, an increase of US$10.7 million (2023:US$18.9 million) predominately due to:

 

·      The change in ARO provisions generated a gain of US$13.8 million in 2024 (2023: US$Nil) primarily related to CWLH (US$11.0 million) and the PenMal Assets (US$2.8 million), driven by changes in underlying assumptions.

 

·      Interest income increased US$3.0 million, due to the CWLH decommissioning trust fund interest increasing US$3.4 million to US$6.3 million (2023: US$2.9 million) following the additional contributions made during the year and an additional US$0.3 million to US$1.3 million (2023: US$1.0 million) earned from the placement of fixed deposits.

 

The above increases were offset by:

 

·      Other provisions decreased by US$6.5 million to a gain of US$1.1 million (2023: US$7.6 million) due to a change in underlying assumptions for provisions for contingent payments and manpower related provisions.

 

·      The Montara helicopter rebate decreased US$0.7 million to US$5.7 million in 2024, compared to US$6.4 million in 2023. The lower rebate in 2024 was due to services being provided for only one helicopter unit, compared to two units in 2023.

 

Other financial gains

 

Other financial gains increased US$2.6 million in 2024, due to the revaluation of the warrant liability. The warrant liability is revalued at each reporting date. This gain reflects a reduction in the liability from US$3.5 million in 2023 to US$0.9 million in 2024.

 

Share of result of associates

 

During 2024, the Group recognized its share of profits from the Sinphuhorm field amounting to US$1.5 million (2023: US$2.6 million). The Group disposed of its Thailand assets in April 2025.

 

Impairment

 

No impairment was recorded in 2024. In 2023, the Group impaired the Stag oil and gas properties by US$17.4 million and US$12.3 million impairment on the PNLP Assets oil and gas properties due to revised ARO estimates.

Taxation

 

The tax expense of US$0.7 million in 2024 (2023: US$11.5 million of tax credit) includes a current tax charge of US$7.1 million (2023: US$10.8 million) and a deferred tax credit of US$6.4 million (2023: deferred tax credit of US$22.3 million). 

 

During the year, tax payments comprised US$14.7 million (2023: US$5.3 million) for Australian corporate taxes. Additionally, there were US$12.3 million (2023: US$7.5 million) in Malaysian petroleum income tax (PITA) payments.

 

The weighted average effective tax rate for operating jurisdictions in Australia and Malaysia was 35% in 2024, based on the profit-making entities within each jurisdiction, compared to 54% in 2023. There was an increase in the deferred tax asset during 2024, resulting from the income tax credits that are generated as trading losses which are carried forward for offset against future taxable profits.

 

 

US$'000	2024 US$'000		2023 US$'000
Loss before tax	(43,435)		(102,766)
Expected effective tax rate	35%		54%
Tax at the country level effective rate	(15,335)		(55,494)
Effect of different tax rates in loss making jurisdictions	5,011		13,975
Malaysia PITA tax losses on non-operated PSCs	8,275		10,060
Utilization of PRRT credits	(10,031)		17,795
PRRT tax refund	(1,700)		1,735
Non-deductible expenses	839		399
Income not subject to tax	(1,897)		-
Deferred tax permanent differences	5,473		2,155
PRRT permanent differences	(1,149)		(4,269)
Deferred tax asset not recognised	12,049		-
Adjustment in respect to prior years	(829)		2,152
Tax expense/(credit) for the year	706		(11,492)

 

Australia taxes

 

The Australian corporate income tax rate is 30% and PRRT is 40%, with the latter being cash based and income tax deductible. The combined standard effective tax rate is 58%, with the actual effective tax rate of 26% in 2024 (2023: 42%) being lower due to the utilization of PRRT credits brought forward and current year business tax losses. Montara and CWLH have approximately US$4.1 billion (2023: US$3.8 billion) and US$802.4 million (2023: US$493.4 million) of unutilized PRRT credits, respectively. Both assets are not expected to incur any PRRT over their economic lives. There was an increase in the deferred tax asset during 2024, resulting from income tax credits as trading losses are carried forward for offsetting against future taxable profits.

 

Malaysia taxes

 

Malaysian PITA is a PSC based tax on petroleum operations at the rate of 38%. There are no other material taxes in Malaysia. 

Indonesia taxes

 

The Indonesia corporate income tax rate is applied at 30% of Indonesia corporate taxable income. Corporate and Dividend Tax ("C&D") is calculated at 20% of sales revenue less certain permitted deductions and is tax deductible for Indonesia corporate income tax purposes. There is no tax expense during the year for Indonesia tax due to the Lemang asset as it is not in a taxable income position.

 

 

RECONCILIATION OF CASH

 

US$'000	2024		2023
Cash and cash equivalents at the beginning of year		153,404		123,329
Revenue	395,036		309,200
Other operating income	6,889		6,574
Production costs	(276,969)		(232,772)
Staff costs	(34,016)		(29,431)
General and administrative expenses	(20,414)		(17,072)
Operating cash flows before movements in working   capital		70,526		36,499
Movement in working capital		10,491		6,837
Placement of decommissioning trust fund for CWLH   Assets		(83,773)		(41,000)
Net tax paid		(27,907)		(14,461)
Investing activities
Purchases of intangible exploration assets, oil and gas   properties, and plant and equipment1		(50,510)		(109,524)
Cash paid on acquisition of Sinphuhorm Assets		-		(27,853)
Dividends received from associate		8,660		3,842
Cash received on acquisition of CWLH		5,236		-
Other investing activities		7,492		4,451
Financing activities
Net proceeds from issuance of shares		-		50,964
Shares repurchased		-		(2,084)
Repayment of lease liabilities		(18,985)		(17,171)
Total drawdown of borrowings		43,000		232,000
Repayment of borrowings		-		(75,000)
Repayment of costs and interests of borrowings		(19,086)		(13,260)
Other financing activities		(3,322)		(4,165)
Total cash and cash equivalent at the end of year		95,226		153,404

 

 

¹ Total capital expenditure was US$74.4 million (2023: US115.9 million), comprising total capital expenditure paid of US$50.5 million (2023: US$109.5 million), accrued capital expenditure of US$18.8 million (2023: US$4.0 million) and capitalization of borrowing costs of US$5.1 million (2023: US$2.4 million ).

 

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/cash.

 

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 associated with the PenMal Assets, expenses related to non-operating assets and DD&A. This definition aims to ensure better comparability between periods.

 

The adjusted production costs are then divided by total produced barrels of oil equivalent for the prevailing period to determine the unit operating cost per barrel of oil equivalent.

 

US$'000 except where indicated		2024		2023
Production costs (reported)		276,969		232,772
Adjustments
Lease payments related to operating activity1		17,538		16,155
Underlift, overlift and crude inventories movement2		(21,411)		9,297
Workover costs3		(20,797)		(17,562)
Other income4		(5,731)		(6,375)
Non-recurring operational costs5		(8,840)		(19,654)
Non-recurring repair and maintenance6		(2,850)		(1,773)
Transportation costs7		(8,451)		(7,502)
PenMal Assets supplementary payments and Australian royalties8		(17,342)		(16,056)
PenMal non-operated assets operational costs9		(262)		(19,273)
Adjusted production costs		208,823		170,029
Total production (barrels of oil equivalent)		6,200,334		4,566,060
Adjusted unit operating costs per barrel of oil equivalent		33.68		37.24

 

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 Non-recurring operational costs mainly 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 Montara Venture FPSO.

⁶ Non-recurring repair and maintenance costs in 2024 predominately related to subsea maintenance at Montara, CALM buoy coating remediation and maintenance pigging of the export flowline at Stag and rectification costs of the cranes and platforms of at one of the PenMal Assets. The cost in 2023 predominately related to the repair of a gas turbine generator at the PenMal Assets PM329 PSC.

 

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

⁸ The 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 are related to an Australian Government mandated decommissioning cost recovery levy on all upstream producers in the country, plus royalties payable from the CWLH fields to the local state government .

⁹ Similar to 2023, PenMal non-operated assets operational costs in 2024 refer to the operating costs incurred at the PNLP Assets, which are excluded as the costs incurred were mainly related to the preservation of facilities and subsea infrastructure and do not contribute to production.

 

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 analyse 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 follow:

 

US$'000	2024		2023
Revenue	395,036		309,200
Production costs	(276,969)		(232,772)
Administrative staff costs	(34,423)		(30,197)
Other expenses and allowance for expected credit losses	(24,316)		(22,841)
Share of results of associate	1,553		2,640
Other income, excluding interest income	22,122		14,404
Other financial gains	2,611		-
Unadjusted EBITDAX	85,614		40,434
Non-recurring
Net loss from oil price and foreign exchange derivatives	27,417		10,395
Non-recurring opex1	11,952		40,700
Oil and gas properties written off	1,423		3,067
Change in provision - Lemang PSC contingent payments	-		(7,653)
Others2	1,489		3,704
	42,281		50,213
Adjusted EBITDAX	127,895		90,647

 

 

¹ Non-recurring opex in 2024 represents 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 repair and maintenance costs  predominately related to CALM buoy coating remediation and maintenance pigging of export flowline at Stag, subsea maintenance at Montara and rectification costs of the cranes and platform of AAKBNLP asset at PenMal. The cost in 2023 mainly consisted of one-off operational costs and major maintenance/well intervention activities, in particular operating costs and FPSO rectification costs incurred at the PNLP Assets, Montara interim tanker storage, diesel fuel consumption by the FPSO during production shutdown and to power the reinjection compressor during production start-up. It also includes repair and maintenance costs related to the repair of a gas turbine generator at PenMal Assets PM329 PSC.

² Includes business development costs, external funding sourcing costs and internal reorganization costs.

 

Net cash/debt

 

Net (debt)/cash is a non-IFRS measure which does not have a standardized definition prescribed by IFRS. Management uses this measure to analyse the net borrowing position of the Group.

 

US$'000	2024		2023
Borrowings (principal sum)	(200,000)		(157,000)
Cash and cash equivalents	95,226		153,404
Net (debt)/cash	(104,774)		(3,596)

 

Net (debt)/cash 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 2024

 

	Notes	2024 USD'000		2023 USD'000
Consolidated statement of profit or loss
Revenue	4	395,036		309,200
Production costs	5	(276,969)		(232,772)
Depletion, depreciation and amortisation	6	(91,407)		(76,141)
Administrative staff costs	7	(34,423)		(30,197)
Other expenses	10	(23,859)		(22,841)
Allowance for expected credit losses	10	(457)		-
Impairment of oil and gas properties	12	-		(29,681)
Share of results of associate accounted for using the equity   method	23	1,553		2,640
Other income	13	29,614		18,855
Finance costs	14	(45,134)		(41,829)
Other financial gains	15	2,611		-
Loss before tax		(43,435)		(102,766)
Income tax (expense)/credit	16	(706)		11,492
Loss for the year		(44,141)		(91,274)
Loss per ordinary share
Basic and diluted (US$)	17	(0.08)		(0.18)
Consolidated statement of other comprehensive income
Loss for the year		(44,141)		(91,274)
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
Loss on unrealised cash flow hedges	34	(14,849)		(30,509)
Hedging loss reclassified to profit or loss	4, 34	27,417		10,322
		12,568		(20,187)
Tax (expense)/credit relating to components of other   comprehensive loss	16	(3,770)		6,056
Other comprehensive income		8,798		(14,131)
Total comprehensive income for the year		(35,343)		(105,405)

 

 

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

 

Consolidated Statement of Financial Position as at 31 December 2024

 

	Notes	31 December 2024 USD'000		31 December 2023 USD'000
Assets
Non-current assets
Intangible exploration assets	19	91,323		79,564
Oil and gas properties	20	422,239		457,202
Plant and equipment	21	10,591		10,462
Right-of-use assets	22	16,111		31,099
Investment in associate	23	19,544		26,651
Other receivables	27	274,124		141,860
Deferred tax assets	25	44,898		26,774
Cash and cash equivalents	28	888		1,008
Total non-current assets		879,718		774,620
Current assets
Inventories	26	44,602		33,654
Trade and other receivables	27	55,044		124,379
Tax recoverable		13,863		4,085
Cash and cash equivalents	28	94,338		152,396
Total current assets		207,847		314,514
Total assets		1,087,565		1,089,134
Equity and liabilities
Equity
Capital and reserves
Share capital	29	457		456
Share premium account	29	52,176		51,827
Merger reserve	31	146,270		146,270
Share-based payments reserve	32	27,730		27,673
Capital redemption reserve	33	24		24
Hedging reserve	34	(5,333)		(14,131)
Accumulated losses		(202,490)		(158,349)
Total equity		18,834		53,770

 

	Notes	31 December 2024 USD'000		31 December 2023 USD'000
Non-current liabilities
Provisions	35	664,951		503,170
Borrowings	36	122,978		131,729*
Lease liabilities	37	5,308		18,746
Other payables	39	17,282		16,966
Derivative financial instruments	40	-		6,708
Deferred tax liabilities	25	59,620		65,829
Total non-current liabilities		870,139		743,148
Current liabilities
Borrowings	36	77,212		22,844*
Lease liabilities	37	12,243		14,118
Trade and other payables	39	92,793		117,984*
Derivative financial instruments	40	7,618		13,972*
Warrants liability	41 XXX	931		3,469
Provisions	35	5,542		108,525
Tax liabilities		2,253		11,304
Total current liabilities		198,592		292,216
Total liabilities TOTAL EQUITY AND LIABILITIES		1,068,731		1,035,364
Total equity and liabilities		1,087,565		1,089,134

*US$15.8 million of borrowings reported as at 31 December 2023 has been reclassified from non-current to current as disclosed in Note 36. US$4.5 million of derivative financial liabilities instruments as at 31 December 2023 has been reclassified to trade and other payables as disclosed in Note 39 and Note 40.