REG - Jadestone Energy PLC - 2025 Half Year Results
Today 07:00
For best results when printing this announcement, please click on link below:
https://newsfile.refinitiv.com/getnewsfile/v1/story?guid=urn:newsml:reuters.com:20250930:nRSd3059Ba&default-theme=true
RNS Number : 3059B Jadestone Energy PLC 30 September 2025
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 Six months Twelve months ended 31 December 2024
ended ended
30 June 30 June
2025 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/day(1) 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 5.59 1.64 3.91
(US$/mscf)
Sales volume for LPG and condensates, barrel (bbls) 514,534 - 150,401
Realized LPG and condensate price per barrel 49.82 - 56.69
(US$/bbl)
Revenue(3) 228,264 185,060 395,036
Production costs (114,565) (136,324) (276,969)
Adjusted unit operating costs per barrel of oil equivalent 24.70 31.72 33.68
(US$/boe)(4)
Adjusted EBITDAX(4) 100,626 60,215 127,895
Profit/(Loss) after tax 32,796 (31,119) (44,141)
Profit/(Loss) per ordinary share: basic and diluted (US$) 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 million(5) 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)
ir@jadestone-energy.com (mailto:ir@jadestone-energy.com)
Stifel Nicolaus Europe Limited (Nomad, Joint Broker) +44 (0) 20 7710 7600 (UK)
Callum Stewart
Jason Grossman
Ashton Clanfield
Berenberg (Joint Broker) +44 (0) 20 3757 4980 (UK)
Ciaran Walsh
Dan Gee-Summons
Ryan Mahnke
Camarco (Public Relations Advisor) +44 (0) 203 757 4980 (UK)
Billy Clegg jse@camarco.co.uk (mailto:jse@camarco.co.uk)
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
(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
(https://www.netroadshow.com/events/global-numbers?confId=88676)
Access Code: 368891
Health, Safety and Environment ("HSE")
Twelve months ended 31 December 2024
Six Months ended 30 June 2025 Six months ended 30 June 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 CO(2)-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/day(1) 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 5.59 1.64 3.91
(US$/mscf)
Sales volume for LPG and condensates, barrel (bbls) 514,534 - 150,401
Realized LPG and condensate price per barrel 49.82 - 56.69
(US$/bbl)
Revenue(3) 228,264 185,060 395,036
Production costs (114,565) (136,324) (276,969)
Adjusted unit operating costs per barrel of oil 24.70 31.72 33.68
equivalent (US$/boe)(4)
Adjusted EBITDAX(4) 100,626 60,215 127,895
Unit depletion, depreciation and amortization 14.15 13.02 12.45
(US$/boe)
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 0.06 (0.06) (0.08)
(US$)
Operating cash flows before movements in working 92,847 27,946 70,526
capital
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 CP(1)
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.
(1)The 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 2024(1)
Cash and cash equivalent at the beginning of 95,226 153,404
period
Revenue 228,264 185,060
Other operating income(2) 5,176 3,525
Production costs (114,565) (136,324)
Administrative staff costs(2) (16,420) (15,541)
General and administrative expenses(2) (9,608) (8,774)
Operating cash flows before movements in 92,847 27,946
working capital
Movements in working capital (57,760) (40,271)
Net tax refunded/(paid) 1,095 (16,486)
Purchases of intangible exploration assets, oil and (60,304) (27,151)
gas properties, and plant and equipment(3)
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 59,042 130,869
period
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.
Twelve months ended
Six months ended 30 June 2025 Six months ended 30 June 31 December 2024
2024
USD'000 except where indicated
Production costs (reported) 114,565 136,324 276,969
Adjustments
Lease payments related to operating activities(1) 7,863 8,764 17,538
Underlift, overlift and crude inventories (12,390) (19,972) (21,411)
movement(2)
Workover costs(3) (2,096) (10,633) (20,797)
Other income(4) (3,139) (3,200) (5,731)
Non-recurring operational costs(5) - (6,775) (8,840)
Non-recurring repairs and maintenance(6) (2,596) (5,343) (2,850)
Transportation costs(7) (4,100) (3,656) (8,451)
Supplementary payments and royalties(8) (11,072) (6,324) (17,342)
PenMal non-operated assets operational costs(9) - (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 24.70 31.72 33.68
equivalent
(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:
Twelve months ended
Six months ended 30 June 2025 Six months ended 30 June 2024 31 December 2024
USD'000
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 1,849 2,124 1,553
using the equity method
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 2,702 15,425 27,417
derivatives
Non-recurring opex(1) 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 - 5,500 -
payments
Others(2) 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.
Twelve months ended
Six months ended 30 June 2025 Six months ended 30 June 2024 31 December 2024
USD'000
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 Six months Twelve months ended 31 December 2024
ended ended
30 June 30 June
2025 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 1,553
using the equity method 11 1,849 2,124
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 (5,180) 5,704 (3,770)
components of other comprehensive loss
Other comprehensive income/(loss) 12,087 (13,311) 8,798
Total comprehensive income/(loss) for the 44,883 (44,430) (35,343)
period/year
Condensed Consolidated Statement of Financial Position as at 30 June 2025
30 June 30 June 31 December 2024
2025 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 30 June 31 December 2024
2025 2024 Audited
Unaudited Unaudited
Reclassified*
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.
Condensed Consolidated Statement of Changes in Equity
for the six months ended 30 June 2025
Share-
Share based Capital
Share premium Merger payments redemption Hedging Accumulated
capital account reserve reserve reserve reserve losses Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
As at 1 January 2024 456 51,827 146,270 27,673 24 (14,131) (158,349) 53,770
Loss for the period - - - - - - (31,119) (31,119)
Other comprehensive loss for the - - - - - (13,311) - (13,311)
period
Loss for the period, representing - - - - - (13,311) (31,119) (44,430)
total comprehensive loss for
the period
Share-based payments - - - 216 - - - 216
Total transactions with owners, - - - 216 - - - 216
recognized directly in equity
As at 30 June 2024 456 51,827 146,270 27,889 24 (27,442) (189,468) 9,556
Share-
Share based Capital
Share premium Merger payments redemption Hedging Accumulated
capital account reserve reserve reserve reserve losses Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
As at 1 January 2024 456 51,827 146,270 27,673 24 (14,131) (158,349) 53,770
Loss for the year - - - - - - (44,141) (44,141)
Other comprehensive income for - - - - - 8,798 - 8,798
the year
Loss for the year, representing - - - - - 8,798 (44,141) (35,343)
total comprehensive income for
the year
Share-based payments - - - 407 - - - 407
Shares issued (Note 14) 1 349 - (350) - - - -
Total transactions with owners, 1 349 - 57 - - - 407
recognized directly in equity
As at 31 December 2024 457 52,176 146,270 27,730 24 (5,333) (202,490) 18,834
Share-
Share based Capital
Share premium Merger payments redemption Hedging Accumulated
capital account reserve reserve reserve reserve losses Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
As at 1 January 2025 457 52,176 146,270 27,730 24 (5,333) (202,490) 18,834
Profit for the period - - - - - - 32,796 32,796
Other comprehensive income for - - - - - 12,087 - 12,087
the period
Profit for the period, representing - - - - - 12,087 32,796 44,883
total comprehensive income for
the period
Share-based payments - - - 318 - - - 318
Total transactions with owners, - - - 318 - - - 318
recognized directly in equity
As at 30 June 2025 457 52,176 146,270 28,048 24 6,754 (169,694) 64,035
Condensed Consolidated Statement of Cash Flows for the six months ended 30
June 2025
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2025 2024 2024
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
Operating activities
Profit/(Loss) before tax 38,073 (29,129) (43,435)
Adjustments for:
Depletion, depreciation and amortization 4 47,265 38,180 91,407
Finance costs 5 28,352 19,520 45,134
Assets written off 622 38 1,775
Share-based payments 318 216 407
Allowance for slow moving inventories - - 1,670
Allowance for expected credit losses - - 457
Change/(reversal of) in provision - 5,500 (14,936)
Interest income (1,544) (3,251) (7,492)
Gain on the sale of Sinphuhorm assets (17,518) - -
Share of result of associate 11 (1,849) (2,124) (1,553)
Other financial gains (872) (1,001) (2,611)
Unrealized foreign exchange loss - (3) (297)
Operating cash flows before movements in 92,847 27,946 70,526
working capital
Increase in trade and other receivables (69,957) (27,286) (63,613)
Decrease in inventories 9,669 29,377 29,954
Increase/(decrease) in trade and other 2,528 (42,362) (39,623)
payables
Cash generated/(used in) from operations 35,087 (12,325) (2,756)
Net tax refund/(paid) 1,095 (16,486) (27,907)
Net cash generated/(used in) operating 36,182 (28,811) (30,663)
activities
Investing activities
Cash received for acquisition of additional 8 - 5,236 5,236
interest of CWLH Assets
Proceeds from the sale of Sinphuhorm Assets 39,352 - -
Payment for oil and gas properties 10 (59,781) (26,362) (48,427)
Payment for plant and equipment 10 (16) (291) (476)
Payment for intangible exploration assets 9 (507) (498) (1,607)
Dividend received from associate 11 - 3,768 8,660
Interest received 1,544 410 7,492
Net cash used in investing activities (19,408) (17,737) (29,122)
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2025 2024 2024
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
Financing activities
Total drawdown of borrowings - 43,000 43,000
Repayment of borrowings (33,252) - -
Interest on borrowings paid (9,376) (8,252) (18,944)
Commitment fees of borrowings paid (270) (142) (142)
Repayment of lease liabilities (9,326) (8,977) (18,985)
Other interest and fees paid (734) (1,616) (3,322)
Net cash (used in)/generated from financing (52,958) 24,013 1,607
activities
Net decrease in cash and cash equivalents (36,184) (22,535) (58,178)
Cash and cash equivalents at beginning of the 95,226 153,404 153,404
period/year
Cash and cash equivalents at end of the 13 59,042 130,869 95,226
period/year
Explanation Notes to the Condensed Consolidated Interim Financial Statements
for the six months ended 30 June 2025
1. GENERAL INFORMATION
Jadestone Energy plc (the "Company" or "Jadestone") is an oil and gas company
incorporated and registered in England and Wales. The Company's registration
number is 13152520. The Company is the ultimate parent company of all
Jadestone subsidiaries (the "Group").
The Company's shares are traded on AIM under the symbol "JSE".
The financial statements are expressed in United States Dollars ("US$" or
"USD").
The Group is engaged in production, development and appraisal activities
across Australia, Malaysia, Indonesia and Vietnam. In April 2025, it completed
the sale of its interest in the Sinphuhorm gas field, located onshore in
northeast Thailand. Its producing assets comprise the Montara Project, Stag
oil field and the Cossack, Wanaea, Lambert, and Hermes (CWLH) oil fields
offshore Western Australia; and the East Piatu, East Belumut, West Belumut,
and Chermingat fields in shallow waters offshore Peninsular Malaysia; and
Akatara gas, LPG and condensate field onshore Indonesia.
The Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower,
Singapore 079909. The registered office of the Company is 6th Floor, 60
Gracechurch Street, London, EC3V 0HR United Kingdom.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PREPARATION
The annual financial statements of the Jadestone Energy plc will be prepared
in accordance with United Kingdom adopted International Accounting Standards.
The condensed set of consolidated financial statements included in this
half‑yearly financial report has been prepared in accordance with United
Kingdom adopted International Accounting Standard 34 'Interim Financial
Reporting'.
These unaudited condensed consolidated interim financial statements do not
comprise statutory accounts within the meaning of section 435 of the Companies
Act 2006 (the "Act"). They do not contain all disclosures required by IFRS for
annual financial statements and should be read in conjunction with the Group's
audited consolidated financial statements for the year ended 31 December 2024.
The information for the year ended 31 December 2024 does not constitute
statutory accounts as defined in section 434 of the Companies Act 2006. A
copy of the statutory accounts for that year has been delivered to the
Registrar of Companies. The auditors reported on those accounts: their report
was unqualified, did not draw attention to any matters by way of emphasis and
did not contain a statement under section 498(2) or (3) of the Companies Act
2006.
These financial statements have been prepared on an historical cost basis,
except for financial instruments classified as financial instruments at fair
value, which are stated at their fair values, and operating leases which are
stated at the present value of future cash payments.
In addition, these financial statements have been prepared using the accrual
basis of accounting.
GOING CONCERN
The Directors have reviewed the Group's forecasts and projections, taking into
account reasonably possible changes in trading performance and the current
macroeconomic environment. Based on this assessment, the Directors have a
reasonable expectation that the Group has adequate resources to continue in
operational existence for the foreseeable future, which represents a period of
at least 12 months from the date of approval of these financial statements
(the "Review Period").
The assessment undertaken included applying appropriate estimates of future
production, associated operating costs and committed capital expenditure.
Consideration was also given to the potential impact of increased uncertainty
and volatility caused by recent geopolitical events on global commodity
markets and modeled through downside oil price sensitivities.
During the first half of the year, US$33.3 million of debt was repaid, leaving
US$166.7 million of debt outstanding. As of 30 June 2025, the Group had
available liquidity of US$88.6 million in cash and cash equivalents, excluding
restricted cash. As at 31 August 2025, the Group had available liquidity of
approximately US$143.3 million, consisting of cash and cash equivalents
(including restricted cash) of US$113.3 million and an undrawn working capital
facility of US$30 million.
Capital expenditure guidance for 2025 was revised in the trading update dated
24 July 2025 from US$75 to US$95 million to between US$105 to US$115 million,
as the cost of the Skua-11ST drilling program exceeded previous forecasts,
partly due to factors outside of Jadestone's control. Since the balance sheet
date, 30 June 2025, Brent crude oil prices have fluctuated between US$65/bbl
to US$80/bbl, which remains within the Group's operating tolerances. The
Group's financial modeling indicates that operations remain viable within this
price range. Additionally, the Group mitigates its exposure to oil price
volatility through hedging, and in June 2025 entered into additional hedges
covering 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.
The Group closely monitors its cash, funding and liquidity position, with both
near-term and longer-term cash projections and underlying assumptions reviewed
and updated regularly to reflect operational and external conditions. The
Group has conducted sensitivity analysis on its cash flow projections,
including scenarios incorporating Brent oil prices modeled at US$60/bbl
combined with additional unplanned downtime, being two separate events at
Montara and CWLH with each event lasting one month (two months in total), with
deferral of capital expenditure and reduction in operating expenditure through
the Review Period. Under these stressed scenarios, together with the projected
borrowing base, the Group's liquidity position remains adequate to meet
operational requirements and debt service obligations throughout the period.
In addition, the Directors believe that there are additional courses of action
available to the Group to create further liquidity, should that be required,
including, but not limited to, the implementation of additional operating cost
efficiencies and an amendment, extension or re-financing of the existing RBL
facility.
The Directors have determined, at the time of approving the financial
statements, that there is reasonable expectation the Group will continue as a
going concern through the Review Period. Accordingly, they have prepared these
audited consolidated financial statements on a going concern basis.
Adoption of new and revised standards
New and amended IFRS standards that are effective for the current period
The Group has applied the following amendments that are relevant to the Group
for the first time with effect from 1 January 2025.
Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates - Lack of exchangeability
The amendments are effective for annual periods beginning on 1 January 2025
and require prospective application. The adoption of these amendments has not
resulted in changes to the Group's accounting policies.
3. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY
Critical accounting judgments and key sources of estimation uncertainty
In the application of the Group's accounting policies, management is required
to make judgments, estimates and assumptions about the carrying amounts of
assets and liabilities that are not readily apparent from other sources. The
estimates and associated assumptions are based on historical experience and
other factors that are considered to be relevant. Actual results may differ
from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognized in the period in which the
estimate is revised, if the revision affects only that period, or in the
period of the revision and future periods, if the revision affects both
current and future periods.
The key judgements and sources of estimation uncertainty remain the same as
disclosed in Jadestone's audited consolidated financial statements for the
year ended 31 December 2024.
4. OPERATING COSTS
Six months ended Six months ended Twelve months ended
30 June 30 June 31 December
2025 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Production costs 110,465 132,668 268,518
Tariffs and transportation costs 4,100 3,656 8,451
Total production costs 114,565 136,324 276,969
Depletion and amortization of oil and 35,082 36,194 77,187
gas properties (Note 10)
Depreciation of plant equipment and 7,802 8,221 16,750
right-of-use assets (Note 10)
Crude inventories movement 4,381 (6,235) (2,530)
Total depletion, depreciation and 47,265 38,180 91,407
amortization
Staff Costs 16,738 15,757 34,423
Total administrative staff costs 16,738 15,757 34,423
Corporate costs 9,608 14,274 20,414
Other operating expenses 622 38 3,445
Total other expenses 10,230 14,312 23,859
5. FINANCE COSTS
Six months ended Six months ended Twelve
months ended
30 June 30 June 31 December
2025 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Interest expense and others 1,981 3,414 5,982
Accretion expense on:
Asset restoration obligations 16,376 10,503 22,544
Reserve based lending facility 9,995 5,372 16,428
Others - 231 180
28,352 19,520 45,134
6. INCOME TAX EXPENSE
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2025 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Current tax
Corporate tax charge 13,811 2,677 1,066
Overprovision in prior year (5,184) (689) (468)
8,627 1,988 598
Australian petroleum resource rent - - (1,700)
tax ("PRRT")
Malaysian petroleum income tax - 5,518 8,275
("PITA")
8,627 7,506 7,173
Deferred tax
Corporate tax (6,031) (7,040) (1,548)
Under/(Over) provision in prior year 810 - (361)
(5,221) (7,040) (1,909)
PRRT 1,871 (5,196) (10,031)
PITA - 6,720 5,473
(3,350) (5,516) (6,467)
5,277 1,990 706
7. PROFIT/(LOSS) PER ORDINARY SHARE
The calculation of the basic and diluted loss per share is based on the
following data:
Six months ended Six months ended Twelve
months ended
30 June 30 June 31 December
2025 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Profit/(Loss) for the purposes of basic 32,796 (31,119) (44,141)
and diluted per share, being the net
profit/(loss) for the period attributable
to equity holders of the Company
Six months ended Six months ended Twelve
months ended
30 June 30 June 31 December
2025 2024 2024
Unaudited Unaudited Audited
Number Number Number
Weighted average number of ordinary 541,110,799 540,795,472 540,848,891
shares for the purposes of basic EPS
Effect of dilutive potential ordinary - - -
shares - share options
Effect of dilutive potential ordinary 42,096 - -
shares - performance shares
Effect of dilutive potential ordinary 3,998,055 - -
shares - restricted shares
Effect of dilutive potential ordinary 30,000,000 - -
shares - warrants
Weighted average number of ordinary 541,110,799 540,795,472 540,848,891
shares for the purposes of diluted EPS
In the prior period and prior year (H1 2024: 54,861, FY2024: 47,139) of
weighted average potentially dilutive ordinary shares available for exercise
from in the money vested options, associated with share options were excluded
from the calculation of diluted EPS, as they are anti-dilutive in view of the
loss for the prior period/year.
In the prior period and prior year (H1 2024: 85,371, FY2024: 70,433) of
weighted average contingently issuable shares associated under the Company's
performance share plan based on the respective performance measures up to
year-end were excluded from the calculation of diluted EPS, as they are
anti-dilutive in view of the loss for the prior period/year.
In the prior period and prior year (H1 2024: 293,655, FY2024: 84,836) of
weighted average contingently issuable shares under the Company's restricted
share plan were excluded from the calculation of diluted EPS, as they are
anti-dilutive in view of the loss for the prior period/year.
In the prior period and prior year (H1 2024: 30,000,000, FY2024: 30,000,000)
of weighted average contingently issuable shares under the Company's
restricted share plan were excluded from the calculation of diluted EPS, as
they are anti-dilutive in view of loss for the prior period/year.
Six months ended Six months ended Twelve
months ended
30 June 30 June 31 December
2025 2024 2024
Profit/(Loss) per share (US$) Unaudited Unaudited Audited
- Basic and diluted 0.06 (0.06) (0.08)
8. ACQUISITION OF INTEREST IN CWLH JOINT OPERATION
8.1. Effective date and Acquisition date
On 14 November 2023, the Group executed a sale and purchase agreement ("SPA")
with Japan Australia LNG (MIMI) Pty Ltd ("MIMI"or "Seller") to acquire MIMI's
non-operated 16.67% working interest in the Cossack, Wanaea, Lambert and
Hermes oil field development (the "CWLH Assets"), offshore Australia. The
initial cash consideration was US$9.0 million.
In addition to the total consideration and as part of this transaction, the
Group was required to pay 16.67% of the participating interest share of the
abandonment amount based on the operator's estimate into a decommissioning
trust fund administered by the operator of the CWLH Assets. The first
tranche of US$42.0 million was paid on closing of the acquisition in February
2024 and a second instalment of US$23.0 million was transferred after the
approval by the Offshore Petroleum & Greenhouse Gas Storage Act (2006)
title registration in April 2024. In July 2024, the operator confirmed the
final payment of US$18.8 million, and this was paid in December 2024. For the
purpose of cash flow, this is disclosed within the working capital movement of
trade and other receivables.
The acquisition completed on 14 February 2024. The acquisition has an economic
effective date of 1 July 2022, which meant the Group was entitled to net cash
generated since effective date to completion date, resulting in a cash receipt
of US$5.2 million at completion. On 14 May 2024, the Group received approval
from the National Offshore Petroleum Titles Administrator ("NOPTA") for the
title transfer.
The legal transfer of ownership and control of the non-operated 16.67% working
interest in the CWLH Assets occurred on the date of completion, 14 February
2024 (the "Acquisition Date"). Therefore, for the purpose of calculating the
purchase price allocation, the Directors have assessed the fair value of the
assets and liabilities associated with the CWLH Assets as at the Acquisition
Date.
8.2. Acquisition of a 16.67% non-operated working interest
The CWLH Assets contain inputs (working interest in the CWLH Assets) and
processes (existing workforce and onshore and offshore infrastructures managed
by the operator), which when combined has the ability to contribute to the
creation of outputs (oil). Accordingly, the CWLH Assets constitute a business
and as a consequence, we have accounted for our acquisition of a 16.67%
working interest in those assets using the accounting principles of business
combinations accounting as set out in IFRS 3, and other IFRSs as required by
the guidance in IFRS 11, paragraph 21A.
A purchase price allocation exercise was performed to identify, and measure at
fair value, the assets acquired and liabilities assumed in the business
combination. The consideration transferred was measured at fair value. The
Group has adopted the definition of fair value under IFRS 13 Fair Value
Measurement to determine the fair values, by applying Level 3 of the fair
value measurement hierarchy.
8.3. Fair value of consideration
After taking into account various adjustments the net consideration for the
CWLH Assets resulted in a cash receipt of US$5.2 million, as set out below:
USD'000
Asset purchase price 9,000
Closing statement adjustments 6 (14,236)
Net cash receipts from the acquisition (5,236)
The Group considers that the purchase consideration and the transaction terms
to be reflective of fair value for the following reasons:
· Open and unrestricted market: there were no restrictions in place
preventing other potential buyers from negotiating with seller during the
sales process period and there were a number of other interested parties in
the formal sale process;
· Knowledgeable, willing and non-distressed parties: both the Group and
Seller are experienced oil and gas operators under no duress to buy or sell.
The process was conducted over several months which gave both parties
sufficient time to conduct due diligence and prepare analysis to support the
transaction; and
· Arm's length nature: the Group is not a related party to Seller. Both
parties had engaged their own professional advisors. There is no reason to
conclude that the transaction was not transacted at arm's length.
8.4. Assets acquired and liabilities assumed at the date of acquisition
During the year, the Group has completed the purchase price assessment ("PPA")
to determine the fair value of the net assets acquired within 12 months from
the acquisition date. The fair value of the identifiable assets and
liabilities have been reflected in the financial statements as at 31 December
2024.
Below are the effects of final PPA adjustments in accordance with IFRS 3:
PPA
USD'000
Asset
Non-current asset
Oil and gas properties (Note 10) 118
Deferred tax assets 19,763
Current asset
Amount due from joint arrangement partner 194
Trade and other receivables 40,602*
60,677
PPA
USD'000
Liabilities
Non-current liabilities
Provision for asset restoration obligations 65,881
Deferred tax liabilities 32
65,913
Net identifiable liabilities assumed (5,236)
* Trade and other receivables consisted of a gross underlift position of
530,484 bbls acquired by the Group, with a fair value of US$40.6 million,
measured at the market price as at closing based on the February 2024 market
value of US$86.27/bbl, less royalties and selling fees. The underlift position
was recognized as an expense in production cost, following a lifting which
occurred in March 2024.
8.5. Impact of acquisition on the results of the Group
The Group's 2024 results included US$56.4 million (H1 2024: US$56.4 million)
of revenue and US$2.0 million (H1 2024: US$2.5 million) of after tax loss
attributable to the acquisition of 16.67% of CWLH Assets.
Acquisition-related costs amounting to US$0.1 million have been excluded from
the consideration transferred and have been recognized as an expense in the
prior year, within "other expenses" line item in the consolidated statement of
profit or loss and other comprehensive income.
Had the business combination been effected at 1 January 2024 and based on the
performance of the business during 2023 under the Seller, the Group would have
generated revenues of US$56.4 million and an estimated net profit after tax of
US$40.6 million. As at acquisition date, there was an underlift position of
530,484 bbls acquired by the Group recognized at fair value of US$40.6
million. This amount is subsequently recognized as an expense in production
cost upon lifting in March 2024, which causes the contribution to the group
upon acquisition of US$2.0 million after tax loss.
9. INTANGIBLE EXPLORATION ASSETS
Total
USD'000
Cost
As at 1 January 2024 79,564
Additions 876((a))
As at 30 June 2024 80,440
Additions 10,883((a)(b))
As at 31 December 2024 91,323
Additions 849((a))
As at 30 June 2025 92,172
Net book value
As at 30 June 2024 (unaudited) 80,440
As at 31 December 2024 (audited) 91,323
As at 30 June 2025 (unaudited) 92,172
(a) For the purpose of the Condensed Consolidated Statement of Cash Flows,
current period expenditure on intangible exploration assets of US$0.3 million
remained unpaid as at 30 June 2025 (H1 2024: US$0.4 million, FY2024: US$0.1
million).
(b) Additions in 2024 includes US$10.0 million arising from provisions for
commitment to drill an exploration well in Nam Du gas field Block 46/07.
10. OIL AND GAS PROPERTIES, PLANT AND EQUIPMENT AND
RIGHT-OF-USE ASSETS
Oil and gas properties Plant and equipment Right-of-use assets
Total
Production assets Development assets
USD'000 USD'000 USD'000 USD'000 USD'000
Cost
As at 1 January 2024 774,012* 122,624* 14,828 48,227 959,691
Additions 4,195((a)) 42,256((a)) 291 - 46,742
Acquisition of additional 12,730((b)) - - - 12,730
interest of CWLH Assets
Adjustment - - - (661) (661)
As at 30 June 2024 790,937 164,880 15,119 47,566 1,018,502
Changes in asset (20,025) 1,330 - - (18,695)
restoration obligations
Acquisition of additional (12,612) - - - (12,612)
interest of CWLH Assets
Additions 15,086 687 185 1,868 17,826
Written off/ (2,965) - - (5,117) (8,082)
derecognition
Transfer - - 208 - 208
Reclassification 166,897((c)) (166,897)((c)) - - -
As at 31 December 937,318 - 15,512 44,317 997,147
2024
Additions 4,108 64,408((d)) 16 2,139 70,671
As at 30 June 2025 941,426 64,408 15,528 46,456 1,067,818
Accumulated depletion,
depreciation,
amortization and
impairment
As at 1 January 2024 439,434 - 4,366 17,128 460,928
Charge for the period 36,194 - 245 7,976 44,415
As at 30 June 2024 475,628 - 4,611 25,104 505,343
Charge for the period 40,993 - 310 8,219 49,522
Written off/ -
derecognition (1,542) - (5,117) (6,659)
As at 31 December 515,079 - 4,921 28,206 548,206
2024
Charge for the period - 207 7,595 42,884
(Note 4) 35,082
As at 30 June 2025 550,161 - 5,128 35,801 591,090
* The opening balance of oil and gas properties amounting to US$4.0 million
has been reclassified from production assets to development assets, to better
reflect the nature of the asset.
Oil and gas properties Plant and equipment Right-of-use assets
Total
Production assets Development assets
USD'000 USD'000 USD'000 USD'000 USD'000
Net book value
As at 30 June 2024 315,309 164,880 10,508 22,462 513,159
(unaudited)
As at 31 December 422,239 - 10,591 16,111 448,941
2024 (audited)
As at 30 June 2025 391,265 64,408 10,400 10,655 476,728
(unaudited)
(a) For the purpose of the Condensed Consolidated Statement of Cash Flows,
current period expenditure on oil and gas properties of US$8.7 million
remained unpaid as at 30 June 2025 (H1 2024: US$15.8 million, FY 2024: US$8.7
million). Additionally, included in the oil and gas properties is the
capitalization of borrowing costs relating to the Akatara development project
of US$Nil (H1 2024: US$4.3 million, FY 2024: US$5.1 million).
(b) On 14 February 2024, the Group obtained additional non-operated 16.67%
working interest in CWLH Asset. As a result, the Group's non-operated interest
in CWLH fields has increased to 33.33% from 16.67% as disclosed in Note 8.
(c) On 31 July 2024, the Group successfully commenced operations of the AGPF
producing gas, LPG and condensate. Accordingly, all oil and gas properties
under development were reclassified to production assets.
(d) Development assets relate to the Skua-11ST well, which commenced
drilling in April 2025. The well was completed and brought onstream in August
2025, at which point the capitalized expenditure was transferred to oil and
gas properties.
11. INVESTMENT IN ASSOCIATE
30 June 30 June 31 December
2025 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
At beginning of period/year 19,544 26,651 26,651
Dividends received during the period/year - (3,768) (8,660)
Share of profit of the associate 1,849 2,124 1,553
Disposal of associate at carrying amount (21,393) - -
At end of period/year - 25,007 19,544
On 19 January 2023, the Group executed a sale and purchase agreement with
Salamander Energy (S.E. Asia) Limited, an affiliate of PT Medco Energi
Internasional Tbk, to acquire its interest in three legal entities, which
collectively own a 9.52% non-operated interest in the producing Sinphuhorm gas
field and a 27.2% interest in the Dong Mun gas discovery onshore north-east
Thailand. The acquisition included a 27.2% interest in APICO LLC, which
operates the Sinphuhorm concessions (E5N and EU1) and Dong Mun (L27/43). The
acquisition was completed on 23 February 2023, for a cash consideration of
US$27.9 million. The acquisition had an economic effective date of 1 January
2022, which meant the Group was entitled to net cash generated since effective
date to completion date.
On 16 April 2025, the Group has divested its 9.52% interest in the producing
Sinphuhorm gas field and Dong Mun discovery 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.
The US$39.4 million received consist of a US$35.0 million base consideration
as of the effective date of 1 January 2025, plus adjustments between the
effective date and closing date of 16 April 2025. A further US$3.5 million in
cash is payable in the event of an extension to either of the two petroleum
licenses which contain the Sinphuhorm gas field, which currently expire in
2029 and 2031, respectively.
No contingent consideration has been recognized in relation to the disposal of
the Sinphuhorm gas field, given the uncertainty regarding the approval of the
license extension.
APICO LLC is limited liability company incorporated in the State of Delaware,
United States of America. Its primary business purpose is the acquisition,
exploration, development and production of petroleum interests in the Kingdom
of Thailand. Its principal activities are currently exploration in operated
concessions and gas production in non-operated concessions.
The Group has applied equity accounting for the investment in associate. The
summarized financial information in respect of the associate, APICO LLC, since
the date of acquisition of 23 February 2023 up tp the disposal date of 16
April 2025 is set out below. The summarized financial information below
represents amounts in APICO LLC's financial statements which holds a 35%
interest in the Sinphuhorm gas field. The APICO LLC's financial statements are
prepared in accordance with IFRS Accounting Standards.
30 December 2024
16 April 2025 30 June 2024 Audited
Unaudited Unaudited USD'000
USD'000 USD'000
Current assets 63,271 29,885 46,414
Non-current assets 103,230 127,552 108,686
Current liabilities 39,446 18,343 34,665
Non-current liabilities 6,443 5,170 6,612
Revenue 21,413 38,565 85,775
Profit before tax 14,032 18,969 45,639
Profit after tax, representing total 6,799 7,808
comprehensive income for the year 5,708
Proportion of the Group's ownership 27.2% 27.2%
interest in the associate 27.2%
Share of profit of the associate 1,849 2,124 1,553
Dividends received from the associate during - (3,768)
the period/year (8,660)
12. TRADE AND OTHER RECEIVABLES
30 June 30 June 31 December 2024
2025 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Current
Trade receivables 79,027 9,274 15,846
Prepayments 5,184 6,709 8,459
Other receivables and deposits 11,421 2,334 7,731
Amount due from joint arrangement partners 2,156 3,493 2,390
(net)
Underlift crude oil inventories 11,171 9,771 12,278
VAT/GST receivables 9,024 1,311 8,797
Malaysia supplementary payment receivable 44 462 -
118,027 33,354 55,501
Allowance for expected credit loss (457) - (457)
117,570 33,354 55,044
Non-current
Other receivables 267,473 244,337 261,517
VAT receivables 13,953 18,156 12,607
281,426 262,493 274,124
398,996 295,847 329,168
Trade receivables originate from revenues earned in Australia, Malaysia, and
Indonesia. The Group has recognized an allowance for expected credit losses of
US$0.5 million from the prior year and remaining outstanding receivables have
been recovered in full.
13. CASH AND BANK BALANCES
30 June 30 June 31 December 2024
2025 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Cash and bank balances, representing cash
and cash equivalents in the consolidated
statement of cash flows, presented as:
Non-current 636 1,356 888
Current 58,406 129,513 94,338
59,042 130,869 95,226
The non-current cash and cash equivalents represents the restricted cash
balance of US$0.6 million (H1 2024: US$1.4 million), in relation to deposits
placed for bank guarantees with respect to the PenMal Assets, Australian
office building, and Indonesia office building respectively.
As at 30 June 2025, the current cash balance included US$9.0 million (H1 2024:
US$8.2 million) in the RBL Debt Service Reserve Account, held in advance of
fees, interest and principal payable in September 2025.
14. SHARE CAPITAL AND SHARE PREMIUM ACCOUNT
Share premium account
Share capital
capital
No. of shares USD'000 USD'000
Issued and fully paid
As at 1 January 2024 540,766,574 456 51,827
Issued during the period 50,570 - -
As at 30 June 2024 540,817,144 456 51,827
Issued during the period 293,655 1 349
As at 31 December 2024/30 June 2025 541,110,799 457 52,176
The Company has one class of ordinary share. Fully paid ordinary shares with
par value of GB£0.001 per share carry one vote per share without restriction
and carry a right to dividends as and when declared by the Company.
15. MERGER RESERVE
The merger reserve arose from the difference between the carrying value and
the nominal value of the shares of the Company, following completion of the
internal reorganization in 2021.
16. CAPITAL REDEMPTION RESERVE
The capital redemption reserve arose from the share buyback program launched
by the Company in August 2022. It represents the par value of the shares
purchased and cancelled by the Company under the share buyback program.
17. HEDGING RESERVE
30 June 30 June 31 December
2025 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
At beginning of the period/year 5,333 14,131 14,131
(Gain)/Loss arising on changes in fair value of (14,565) 34,440 14,849
hedging instruments during the period/year
Income tax related to gain/loss recognized in 4,370 (10,332) (4,455)
other comprehensive income
Net loss reclassified to profit or loss (2,702) (15,425) (27,417)
Income tax related to amounts reclassified to 810 4,628 8,225
profit or loss
At end of the period/year (6,754) 27,442 5,333
The hedging reserve represents the cumulative amount of gains and losses on
hedging instruments deemed effective in cash flow hedges. The cumulative
deferred gain or loss on the hedging instrument is recognized in profit or
loss only when the hedged transaction impacts the profit or loss.
18. PROVISIONS
30 June 30 June 31 December 2024
2025 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Non-current
Asset restoration obligations 670,992 681,484 654,662
Others 10,344 1,431 10,289
681,336 682,915 664,951
Current
Asset restoration obligations 4,109 - 4,109
Others 1,440 11,994 1,433
5,549 11,994 5,542
686,885 694,909 670,493
19. BORROWINGS
30 June
30 June 2024 31 December
2025 Unaudited 2024
Unaudited Reclassified* Audited
USD'000 USD'000 USD'000
Non-current secured borrowings
Reserve based lending facility 56,952 148,787* 122,978
Current secured borrowings
Reserve based lending facility 110,605 50,177* 77,212
167,557 198,964 200,190
On 19 May 2023, the Group entered into a US$200.0 million RBL facility with
four international banks, with a fifth bank joining on 15 November 2023. The
facility has a four-year term, maturing on the earlier of 31 March 2027 or the
projected reserves tail 7 .
The facility carries interest at 4.50% over SOFR, plus a credit spread of
0.11%-0.45% depending on the interest period, along with standard arrangement
and commitment fees.
The facility limit remains at US$200.0 million, with a borrowing base 8 of
US$167.7 million as at 30 June 2025 (H1 2024: US$200.0 million) after a
US$33.3 million repayment on 17 April 2025. Loans had an amortized carrying
value of US$167.6 million and accretion expenses of US$10.0 million were
incurred during H1 2025.
On 10 April 2025, The Group entered into a US$30.0 million working capital
facility with a maturity date of 31 December 2026. The facility carries a SOFR
plus 7% margin and was undrawn as of 30 June 2025. The facility, if required,
may be drawn upon to support general corporate purposes.
*US$20.3 million of borrowings reported as at 30 June 2024 has been
reclassified to current following changes in the basis of assumption.
20. TRADE AND OTHER PAYABLES
30 June
30 June 2024 31 December 2024
2025 Unaudited Audited
Unaudited Reclassified* USD'000
USD'000 USD'000
Current
Trade payables 15,043 17,268 26,520
Other payables 15,865 15,116* 12,809
Accruals 74,350 54,662 51,805
Malaysian supplementary payment payables - - 392
Amount due to joint arrangement partner (net) 2 3,138 1,082
GST/VAT payables 181 655 185
105,441 90,839 92,793
Non-current
Other payables 16,917 16,917 16,917
Accruals 365 420 365
17,282 17,337 17,282
122,723 108,176 110,075
*US$2.5 million relating to outstanding swap contracts that matured in quarter
2 in 2024 and were settled in July 2024 have been reclassified from derivative
financial instruments to other payable as at 30 June 2024.
21. DERIVATIVE FINANCIAL INSTRUMENTS
The Group uses derivatives to manage its exposure to oil price fluctuations.
Oil hedges are undertaken using swaps. All contracts are referenced to Dated
Brent oil prices. During the period, the Group entered into commodity swaps
that are designated as a cash flow hedge. All hedging undertaken during H1
2025 was deemed effective.
30 June
30 June 2024 31 December
2025 Unaudited 2024
Unaudited Reclassified* Audited
USD'000 USD'000 USD'000
Derivative financial assets
Designated as cash flow hedges
Commodity swap 9,649 - -
9,649 - -
Analyzed as:
Current 8,591 - -
Non-current 1,058 - -
9,649 - -
Derivative financial liabilities
Designated as cash flow hedges
Commodity swap - 39,201* 7,618
- 39,201* 7,618
Analyzed as:
Current - 33,304* 7,618
Non-current - 5,897 -
- 39,201 7,618
*US$2.5 million relating to outstanding swap contracts that matured in quarter
2 in 2024 and were settled in July 2024 have been reclassified from derivative
financial instruments to other payable as at 30 June 2024.
The following is a summary of the Group's outstanding derivative contracts:
Fair value asset/ Fair value asset/ Fair value asset/
(liabilities) at (liabilities) at (liabilities) at
30 June 2025 30 June 2024 31 December
Contract quantity Type of contracts Hedge classification Unaudited Unaudited 2024
Terms Contract price USD'000 USD'000 Audited
USD'000
Contracts designated as cash flow hedges
50% of Commodity Oct Weighted Cash flow 9,649 (39,201) (7,618)
Group's swap: swap 2023 - average price
planned component Sep of
2PD 2026* US$70.45/bbl
production (H1 2024:
US$69.69,
2024:
US$70.57)
*On 20 June 2025, the Group entered into additional commodity swap contracts,
extending the terms from September 2025 to September 2026.
22. WARRANTS LIABILITY
On 6 June 2023, in consideration of the support provided to the Company under
the equity underwrite debt facility and committed standby working capital
facility, the Company entered into a warrant instrument with Tyrus Capital
S.A.M. and funds managed by it, for 30 million ordinary shares at an exercise
price of 50 pence sterling per share. The warrants are exercisable within 36
months from the date of issuance, with an expiry date of 5 June 2026.
Management applies the Black-Scholes option-pricing model to estimate the fair
value of warrants. As of 30 June 2025, the fair value of warrants liability
was US$0.1 million (H1 2024: US$2.5 million) as compared to the fair value of
warrants as of 31 December 2024 of US$0.9 million. The differences of the fair
value of warrants of US$0.8 million were recorded under other financial gains
in the Condensed Consolidated Statements of Profit and Loss and Other
Comprehensive Income.
The Directors have applied the Black-Scholes option-pricing model, with the
following assumptions, to estimate the fair value of the warrants as at
period/year-end:
As at 30 June 2024 As at 31 December
As at 30 June 2025 2024
Risk-free rate 3.75% 4.20% 4.48%
Expected life 0.9 years 2.0 years 1.4 years
Expected volatility 9 45.93% 63.09 59.5%
Share price GB£ 0.21 GB£ 0.31 GB£ 0.24
Exercise price GB£ 0.50 GB£ 0.50 GB£ 0.50
Expected dividends 0% 0% 0%
23. SEGMENT INFORMATION
Information reported to the Group's Chief Executive Officer (the chief
operating decision maker) for the purposes of resource allocation is focused
on two reportable/business segments driven by different types of activities
within the upstream oil and gas value chain, namely producing assets and
secondly development and exploration assets. The geographic focus of the
business is on Southeast Asia ("SEA") and Australia.
Revenue and non-current assets information based on the geographical location
of assets respectively are as follows:
Producing assets Exploration/
development
Australia Malaysia((a)) Indonesia((a)) Thailand((a)) Vietnam((a)) Indonesia((a)) Corporate Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
Six months ended 30 June 2025 (unaudited)
Revenue
Liquids revenue 158,594 24,566 25,632 - - - - 208,792
Gas revenue - 393 19,079 - - - - 19,472
158,594 24,959 44,711 - - - - 228,264
Production cost (92,362) (13,761) (8,442) - - - (114,565)
DD&A (38,073) (1,814) (7,206) - (42) - (130) (47,265)
Administrative staff costs (6,334) (1,648) (2,475) - (659) - (5,622) (16,738)
Other expenses (4,376) (1,942) (1,809) (30) (130) - (1,943) (10,230)
Share of results of associate - 1,849 - - 1,849
accounted for using the equity
method - - -
Other income 5,756 425 371 1 9 - 17,676 24,238
Finance costs (13,363) (3,803) (15) - (3) - (11,168) (28,352)
Other financial gains - - - - - - 872 872
Profit/(Loss) before tax 9,842 2,416 25,135 1,820 (825) - (315) 38,073
Producing assets Exploration/
development
Australia Malaysia((a)) Indonesia((a)) Thailand((a)) Vietnam((a)) Indonesia((a)) Corporate Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
Six months ended 30 June 2025 (unaudited)
Additions to non-current assets 71,143 2,085 3,469 (19,544) 815 - 1,058 59,026
Non-current assets 296,995 293,924 174,651 - 84,862 - 1,588 852,020
Twelve months ended 31 December 2024 (audited)
Revenue
Liquids revenue 301,886 76,661 4,214 - - - - 382,761
Gas revenue - 1,600 10,675 - - - - 12,275
301,886 78,261 14,889 - - - - 395,036
Production cost (221,844) (43,277) (11,848) - - - - (276,969)
DD&A (77,297) (10,956) (2,809) - (89) - (256) (91,407)
Administrative staff costs (15,082) (5,427) (393) - (1,162) (535) (11,824) (34,423)
Other expenses (8,949) (4,693) (2,763) (1,623) (463) (624) (4,744) (23,859)
Allowance for expected credit losses - - (457) - - - - (457)
Share of results of associate - 1,553 - - 1,553
accounted for using the equity
method - - -
Other income 25,370 3,618 44 7 - - 575 29,614
Finance costs (24,444) (4,108) (734) (1) (6) - (15,841) (45,134)
Other financial gains - 73 - - - - 2,538 2,611
(Loss)/Profit before tax (20,360) 13,491 (4,071) (64) (1,720) (1,159) (29,552) (43,435)
Additions to non-current assets 103,022 43,000 535 - 11,837 42,309 - 200,703
Non-current assets 262,784 289,530 178,501 19,544 84,056 - 405 834,820
Producing assets Exploration/
development
Australia Malaysia((a)) Indonesia((a)) Thailand((a)) Vietnam((a)) Indonesia((a)) Corporate Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
Six months ended 30 June 2024 (unaudited)
Revenue
Liquids revenue 135,279 48,865 - - - - - 184,144
Gas revenue - 916 - - - - - 916
135,279 49,781 - - - - - 185,060
Production cost (116,424) (19,900) - - - - - (136,324)
DD&A (31,850) (6,078) - - (46) (79) (127) (38,180)
Administrative staff costs (7,682) (2,553) - - (562) (210) (4,750) (15,757)
Other expenses (2,671) (2,122) - (953) (160) (6,400) (2,006) (14,312)
Share of results of associate - 2,124 - - 2,124
accounted for using the equity
method - - -
Other income 6,293 123 - 3 - 11 349 6,779
Finance costs (13,927) (3,347) - - - (297) (1,949) (19,520)
Other financial gains - 73 - - - - 928 1,001
(Loss)/Profit before tax (30,982) 15,977 - 1,174 (768) (6,975) (7,555) (29,129)
Additions to non- current assets 70,962 49,820 - (1,644) 44,448 3,022 - 166,608
Non-current assets 323,862 301,122 - - 73,202 183,754 515 882,455
(a) The SEA category under producing assets from the prior years has been
split into Malaysia, Indonesia and Thailand, while the exploration/development
category has been separated into Vietnam and Indonesia. Accordingly, the prior
year figures have been reclassified to reflect these changes.
Non-current assets in the table comprises intangible exploration assets, oil
and gas properties, right-of-use assets, plant and equipment used in corporate
offices, investment in associate, other receivables, derivative financial
instruments and cash and cash equivalents. Deferred tax assets are excluded
from the segmental note but included in the Group's consolidated statement of
financial position.
Revenue arising from producing assets relates to the Group's single customer
with respect to oil sales in Australia, a different single customer for oil
and gas sales in Malaysia, different single customer for gas sales in
Indonesia and several customers for LPG and condensate sales in Indonesia.
There is an active market for the Group's oil and gas production so they can
be sold to other buyers, if required.
24. CONTINGENT LIABILITIES
Montara Venture FPSO investigation
On 17 June 2022, a loss of containment of between three and five cubic metres
of oil occurred at the Montara Venture FPSO. The facility was shut-in
immediately and the incident was reported to the local regulator. The local
regulator commenced an investigation into the incident in 2022 for potential
breach of the local regulations. The investigation is ongoing as at 30 June
2025 and it is unknown when investigation will be completed or if any
prosecution will eventuate.
Akatara Gas development Change Orders
The Akatara Gas Facility achieved first gas on 31 July 2024 and completed its
formal EPCI contractual performance test in December 2024.
As part of the final project reconciliation for Akatara, the Group has
provided the aggregate acceptable value to the Contractor concerning change
orders raised over the course of the project. Any final agreement would
depend on the assessment of all contractual obligations, documentation of
approved modifications and resolution of any outstanding claims from both
parties.
25. EVENTS AFTER THE END OF THE REPORTING PERIOD
Skua-11ST drilling campaign
On 31 March 2025, the Group commenced drilling the Skua-11 well sidetrack
within the Montara license. The well reached its target depth in July 2025,
later than originally anticipated due to external factors. Production
commenced in early August 2025, with initial oil production rates from the
well exceeding 6,000 bbls/d, significantly ahead of previous guidance of 3,500
bbls/d.
Glossary
2P the sum of proved and probable reserves, reflecting those reserves with 50%
probability of quantities actually recovered being equal or greater to the sum
of estimated proved plus probable reserves
AAKBNLP Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields
AGPF Akatara Gas Processing Facility
AIM Alternative Investment Market
ARO Asset restoration obligations
API American Petroleum Institute gravity
bbl barrel
bbls/d barrels per day
bcf billion standard cubic feet
the Board the board of directors of Jadestone Energy plc
boe barrels of oil equivalent
boe/d barrels of oil equivalent per day
CALM catenary anchor leg mooring
CO(2)-e carbon dioxide equivalent
the Company Jadestone Energy plc
CWLH Cossack, Wanaea, Lambert and Hermes oil fields offshore Australia
DD&A depletion, depreciation and amortization
EBITDAX earnings before interest tax, depreciation, amortization and exploration
EPCI engineering, procurement, construction and installation
ESG Environment, Social and Governance
FDP field development plan
FOB free on board, a commercial structure for selling oil, where the buyer takes
responsibility for the cargo and transportation costs after loading onto an
offtake tanker
FPSO floating production storage and offloading
GB£ British pound sterling
GHG greenhouse gases
the Group Jadestone Energy plc and its subsidiaries
GSPA gas sales and purchase agreement
IAS International Accounting Standards
IEA the International Energy Agency
IFRS International Financial Reporting Standards
LPG Liquefied petroleum gas
mcf thousand cubic feet of natural gas
mscf thousand standard cubic feet of natural gas
mm million
mmbbls million barrels
mmboe million barrels of oil equivalent
mmscf/d million standard cubic feet per day
mmscf million standard cubic feet
NDUM Nam Du and U Minh gas fields offshore Vietnam
NOPSEMA National Offshore Petroleum Safety and Environmental Management Authority
opex operating expenditure
PenMal Assets collectively, Jadestone's Peninsular Malaysia assets
PETRONAS Petroliam Nasional Berhad
PITA Petroleum Income Tax
PNLP Assets collectively, a number of oil fields offshore Peninsular Malaysia in which
Jadestone acquired a non-operated interest as part of its wider Peninsular
Malaysia entry in 2021. These assets, originally known as the PM318/AAKBNLP
PSCs, were renamed the PNLP Assets after Jadestone assumed operatorship of the
licenses in April 2023 following the withdrawal of the previous operator.
Certain of the PNLP Assets were included in the Malaysia Bid Round Plus, with
Jadestone subsequently being awarded a 100% interest in the Puteri Cluster in
2024
PRRT Petroleum Resource Rent Tax
PSC production sharing contract
R&M repairs and maintenance
RBL reserve based loan
RBL Facility the Group's US$200 million reserve based lending facility closed in May 2023
with a four-year tenor
reserves hydrocarbon resource that is anticipated to be commercially recovered from
known accumulations from a given date forward
SOFR Secured Overnight Financing Rate
US$ or USD United States dollar
The technical information contained in this announcement has been prepared in
accordance with the June 2018 guidelines endorsed by the Society of Petroleum
Engineers, World Petroleum Congress, American Association of Petroleum
Geologists and Society of Petroleum Evaluation Engineers Petroleum Resource
Management System.
A. Shahbaz Sikandar of Jadestone Energy plc, Group Subsurface Manager with a
Masters degree in Petroleum Engineering and who is a member of the Society of
Petroleum Engineers and has worked in the energy industry for more than 25
years, has read and approved the technical disclosure in this regulatory
announcement.
The information contained within this announcement is considered to be inside
information prior to its release, as defined in Article 7 of the Market Abuse
Regulation No. 596/2014 which is part of UK law by virtue of the European
Union (Withdrawal) Act 2018, and is disclosed in accordance with the Company's
obligations under Article 17 of those Regulations.
1 Inclusive of restricted cash
2 To 21 September 2025
3 Based on a Brent oil price range of US$70-80/bbl (real terms from 2025).
Assumes midpoint of internal production expectations and that all barrels
produced during 2025-27 are sold in the period. Does not reflect any capital
expenditure or abandonment spend outside the Group's producing assets.
Reflects upfront consideration from the sale of the Group's assets in Thailand
on 16 April 2025.
4 Includes 100% of GHG emissions from Montara, Stag, PenMal sites and
Akatara gas and liquids field.
5 The local government has an option to take a 10% participating interest in
the Lemang PSC, which, if exercised, would reduce Jadestone's working interest
in the Akatara field to 90%.
6 The closing adjustment represents the economic benefits of production
since the effective date and completion.
7 Reserves tail date refers to the last day of the quarter immediately
preceding the quarter in which the remaining borrowing base reserves are
forecast to be 25 per cent (or less) of the initial approved borrowing base
reserves.
8 The borrowing base represents the maximum loan amount that can be drawn
under the RBL at any given time, subject to a redetermination every six months
through the life of the loan.
9 Expected volatility was determined by calculating the average historical
volatility of the daily share price returns over a period commensurate with
the expected life of the awards for a group of ten peer companies.
This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact
rns@lseg.com (mailto:rns@lseg.com)
or visit
www.rns.com (http://www.rns.com/)
.
RNS may use your IP address to confirm compliance with the terms and conditions, to analyse how you engage with the information contained in this communication, and to share such analysis on an anonymised basis with others as part of our commercial services. For further information about how RNS and the London Stock Exchange use the personal data you provide us, please see our
Privacy Policy (https://www.lseg.com/privacy-and-cookie-policy)
. END IR PKCBDKBKBKCBRecent news on Jadestone Energy
See all newsREG - Jadestone Energy PLC - 2025 Half Year Results
AnnouncementREG - Jadestone Energy PLC - Holdings in Company: Baillie Gifford
AnnouncementREG - Jadestone Energy PLC - Notice of First-Half 2025 results
AnnouncementREG - Jadestone Energy PLC - Block Listing Six Monthly Return
AnnouncementREG - Jadestone Energy PLC - Successful Flow Testing of the Skua-11ST Well
Announcement