REG - Jadestone Energy PLC - 2025 Full-Year Results
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RNS Number : 8815E Jadestone Energy PLC 19 May 2026
2025 Full-Year Results
19 May 2026 - Singapore: Jadestone Energy PLC (AIM:JSE) ("Jadestone" or the
"Company"), an independent upstream company and its subsidiaries (the
"Group"), focused on the Asia-Pacific region, reports its consolidated audited
financial statements (the "Financial Statements"), as at and for the financial
year ended 31 December 2025.
The Company will host a webcast at 9.00 a.m. UK time today, details of which
can be found in the announcement below.
T. Mitch Little, Chief Executive Officer, commented:
"Jadestone's improved operational performance and cash flow generation in 2025
reflect the organization's hard work and relentless focus on the operational
excellence and cost discipline principles which have been instilled under the
leadership of our refreshed management team. These results were also
underpinned by another excellent year of HSE performance across the Group.
However, our financial results were impacted by the previously disclosed
impairment, which was the main driver of a loss after tax for the year.
Protecting the base business will remain a key focus for the Group, as we work
to return to sustainable profits and maximize cash generation to support our
future growth ambitions.
The strong momentum from 2025 continued into early 2026, where we have already
delivered on several of our key near-term priorities for the year. In Vietnam,
we achieved FDP approval and signature of the GSPA for the Nam Du/U Minh
project, clearing the key regulatory and commercial milestones required for
project execution. The farm-out process has now commenced, and we have been
encouraged by both the number and quality of interested parties to date.
Separately, we have refinanced our debt with the issuance of our debut bond,
removing near-term debt repayments and allowing us to focus near-term cashflow
on accretive growth opportunities.
After excellent operating performance in the first quarter of 2026, where we
delivered on plan against all key metrics, the second quarter has started with
some operational headwinds, primarily associated with the effects of Cyclone
Narelle, one of the strongest storms to pass through offshore Western
Australia in recorded history. The full impact of the storm is still being
assessed, but will likely result in the Stag field remaining offline until the
fourth quarter of this year based on current information.
The Okha FPSO has arrived back on station at the CWLH fields following its
successful dry-dock. However, recent subsea inspections have established that
some minor structural repairs may be required to one of the field's subsea
riser's J tube before re-connecting the vessel to the Riser Turret Mooring.
Recent events in the Middle East continue to highlight the strategic value of
a diversified portfolio of upstream assets in the Asia-Pacific region -
reinforcing our long-standing corporate strategy. We remain geared towards
Brent oil price strength, seeing realized prices for our oil sales increase
significantly in recent months, with a positive impact on our financial
performance. Combined with the bond issue, our financial position has
strengthened significantly since the beginning of the year."
2025 - a year of record production, safe operations and portfolio value
creation
l Over 12 million manhours worked without a lost-time injury ("LTI") across
the Group.
l Delivered record annual production of 19,829 boe/d in 2025 (+6%
year-on-year).
l Successful drilling of the Skua-11ST well at Montara in Australia, which
extended field life by one year and reduced Montara unit operating costs.
l Sale of the Group's interest in the Sinphuhorm field onshore Thailand for
US$39.4 million and contingent payments, representing a 44% return on the
Group's ownership and in line with the independently assessed 2P NPV10 of the
asset at year-end 2024.
l Independently audited 2P reserves by Sproule ERCE of 56.2 MMboe at year-end
2025 (year-end 2024: 68.3 MMboe), with the reduction from the prior year
primarily due to 7.0 MMboe of production in 2025, the sale of the Group's
Sinphuhorm interest and the remainder due to technical and economic revisions.
In March 2026, significant 2P reserves were booked in relation to the Group's
Vietnam assets (see below).
l Year-end 2025 2C resources of 121.7 MMboe (year-end 2024: 125.7 MMboe)
reflecting the sale of the Sinphuhorm asset and prior to the Vietnam reserves
booking in March 2026.
Higher liftings and lower costs drive significant cashflow generation
l 2025 revenues increased by 3% year-on-year to US$408.1 million (2024:
US$395.0 million).
l 2025 production costs decreased by 19% year-on-year to US$232.7 million
(2024: US$286.9 million 1 (#_ftn1) ), primarily due to lower field operating
costs, workovers, repairs and maintenance activity and reduced lifting and
inventory charges.
¡ On an adjusted basis, unit operating costs declined 21% year-on-year to
US$28.02/boe (2024: US$35.28/boe)
l 2025 adjusted EBITDAX of US$153.0 million, a 20% increase year-on-year,
driven primarily by higher revenues and lower production costs.
l 2025 loss after tax for the period of US$110.7 million (2024: US$44.1
million loss after tax), driven by a post-tax impairment of US$88.2 million,
in line with the figure disclosed on 26 February 2026.
l 2025 operating cash flow pre working capital of US$123.6 million, a 75%
increase year-on-year (2024: US$70.5 million)
l Net debt at 31 December 2025 was US$89.1 million, a 15% reduction
year-on-year (31 December 2024: US$104.8 million). The net debt figure at 31
December 2025 excluded US$23.7 million of proceeds related to liftings in
December 2025 received in early 2026.
Current trading and outlook - strengthened financial platform with growing
momentum in Vietnam
l In March 2026, the Group successfully placed a Nordic bond issue of US$200
million with a 2031 maturity and a 12% coupon. The bond placement was
materially oversubscribed and saw strong investor demand across Nordic and
international markets. The net proceeds from the bond issue will be used to
repay the Group's outstanding US$122.0 million balance on its reserves-based
lending facility (the "RBL Facility"), with the remainder used for general
corporate purposes.
l In March 2026, Jadestone received Vietnam government approval for the Nam
Du/U Minh field development plan, allowing the Group to book initial 2P
reserves for the project of approximately 32 MMboe. In April 2026, the gas
sales and purchase agreement for the supply of gas from Nam Du/U Minh was
signed. Jadestone's near-term priorities are to conclude the bid evaluation
for the FPSO and field infrastructure, and award their respective contracts,
during the second half of 2026. A formal farm-out process has been launched to
seek partner(s) for the project.
l The PM323 East Belumut infill drilling campaign commenced in April 2026. The
two firm plus one contingent well program is designed to follow up on the very
successful 2023 infill drilling campaign by targeting the previously
undeveloped southwest extension of the East Belumut field. The results of the
first well are due in late Q2 2026.
l 2026 production to the end of April has averaged ~16,300 boe/d, primarily
reflecting planned downtime at CWLH for the five-yearly class certification
and maintenance dry dock of the Okha FPSO and unplanned downtime at Stag from
the Cyclone Narelle impact. The Okha FPSO has arrived back on station at the
CWLH fields following its successful dry-dock. However, recent subsea
inspections have established that some minor structural repairs may be
required to one of the field's subsea riser's J tube before re-connecting the
vessel to the Riser Turret Mooring. Dependent on the ongoing analysis of the
inspection findings, production could be restarted as early as end-May, or if
repairs are required, these are expected to be executed within 5-8 weeks.
l The Stag field remains shut in due to the impact of Cyclone Narelle. The
main storm damage was to the field's CALM buoy, through which shuttle tankers
offload crude produced from Stag. Efforts are underway to ready the CALM buoy
for tow to shore, where a full damage assessment will be undertaken to inform
next steps, with current expectations of a return to production in the fourth
quarter of 2026. The Group has appropriate insurance in place, for both
physical damage and business interruption, and is working with insurers
through the standard claims process.
l Net debt at 30 April 2026 was approximately US$5 million, consisting of
US$117.4 million in cash (incl. restricted cash) and US$122 million of
outstanding debt on the RBL Facility. The Group's US$30 million Working
Capital Facility remains undrawn.
l The Group's has hedged approximately 1.5 MMbbls for the period April to
December 2026 at a weighted average price of US$70/bbl Brent (not including
any asset specific premiums or discounts).
Guidance - remains unchanged
l The Group's production guidance of 18,000 - 21,000 boe/d, is unchanged
pending further clarity on the restoration of production from the Stag,
although an outcome in the lower half of the range is currently considered
most likely.
l Total production costs 2 (#_ftn2) (unchanged): US$260-300 million, with an
outcome in the lower half of the range currently considered most likely due to
operating cost reductions at Stag during the shut-in period.
l Capital expenditure guidance (unchanged): US$50-80 million. Consistent with
earlier disclosures, the guidance range reflects expenditure on the Group's
existing producing assets, with only a small amount budgeted for pre-sanction
costs in Vietnam.
l Based on information currently available, Jadestone does not expect the Stag
shut-in to have a material financial impact on the Group's current year or
longer-term cashflow projections.
l 2025-27 unlevered free cash flow guidance 3 (#_ftn3) (unchanged):
US$200-240 million at US$70/bbl Brent. Every US$10/bbl move in the underlying
Brent assumption is estimated to change the 2025-2027 free cash flow guidance
by ±US$90 million.
-ends-
Enquiries
Jadestone Energy plc.
Phil Corbett, Head of Investor Relations +44 7713 687 467 (UK)
ir@jadestone-energy.com (mailto:ir@jadestone-energy.com)
Stifel Nicolaus Europe Limited (Nomad, Joint Broker) +44 (0) 20 7710 7600 (UK)
Callum Stewart / Jason Grossman / Ashton Clanfield
Berenberg (Joint Broker) +44 (0) 20 3207 7800 (UK)
Ciaran Walsh / Dan Gee-Summons / Ryan Mahnke
Camarco (Public Relations Advisor) +44 (0) 20 3757 4980 (UK)
Billy Clegg / Georgia Edmonds / Poppy Hawkins jadestone@camarco.co.uk (mailto:jadestone@camarco.co.uk)
Full-year 2025 presentation webcast
The Company will host an investor and analyst presentation at 9:00 a.m. (UK
time) on Tuesday, 19 May 2026, including a question-and-answer session,
accessible through the link below:
Webcast link:
https://www.investis-live.com/jadestone-energy/69ef1e25fed46a000ff0608b/klaty
(https://apc01.safelinks.protection.outlook.com/?url=https%3A%2F%2Fwww.investis-live.com%2Fjadestone-energy%2F69ef1e25fed46a000ff0608b%2Fklaty&data=05%7C02%7Cpcorbett%40jadestone-energy.com%7C7ff1af250c18416a36c908dea43db7da%7C05c124ff37ea4b96b46f7764de1d4f38%7C1%7C0%7C639128782827177800%7CUnknown%7CTWFpbGZsb3d8eyJFbXB0eU1hcGkiOnRydWUsIlYiOiIwLjAuMDAwMCIsIlAiOiJXaW4zMiIsIkFOIjoiTWFpbCIsIldUIjoyfQ%3D%3D%7C0%7C%7C%7C&sdata=PzmakbkYACrqw%2BP3MXourgeXWGYPf1gZJFVVQyHxuuA%3D&reserved=0)
Event title: Jadestone Energy Full-Year 2025 Results
Time: 9:00 a.m. (UK time)
Date: 19 May 2026
To join the presentation by phone, please use the below dial-in details from
the United Kingdom or the link for global dial-in details:
United Kingdom (Local): +44 20 3936 2999
United Kingdom (Toll-Free): +44 808 189 0158
Global Dial-In Details:
https://www.netroadshow.com/events/global-numbers?confId=102519
Access Code: 205105
2025 SUMMARY
US$'000 except where indicated 2025 2024
( ) ( )
Total hours without a life-altering event (millions) 1.95 5.41
Total lost-time injury rate 0.00 0.18
Proven plus Probable Reserves (MMboe) - 31 December 4 (#_ftn4) 56.2 68.3
Production, boe/day 5 (#_ftn5) 19,829 18,696
Oil sales volume, barrels (bbls) 4,230,397 4,764,875
Realized oil price per barrel (US$/bbl) 6 (#_ftn6) 74.42 85.21
Gas sales volume, thousand standard cubic feet (Mscf) 7,052,210 2,216,652
Realized gas price per thousand standard cubic feet 5.83 3.91
(US$/Mscf)
LPG and condensate sales volume, barrels (bbls) 1,085,482 150,401
Realized LPG and condensate price per barrel (US$/bbl) 45.89 56.69
Revenue 7 (#_ftn7) 408,060 395,036
Production costs (232,660) (286,908) 8 (#_ftn8)
Impairment of oil and gas properties (pre-tax) 9 (#_ftn9) (126,040) -
Adjusted unit operating costs per barrel of oil equivalent 28.02 35.288
(US$/boe) 10 (#_ftn10)
Adjusted EBITDAX(10) 152,963 127,895
Loss after tax (110,747) (44,141)
Loss per ordinary share: basic & diluted (US$) (0.20) (0.08)
Operating cash flows before movement in working capital 123,637 70,526
Capital expenditure 92,807 74,459
Net debt at 31 December(12) (89,084) (104,774)
Certain 2024 comparative information has been reclassified. A total of US$9.9
million was reclassified to production costs, comprising US$9.8 million from
administrative staff costs and US$0.1 million from other expenses to operating
costs, to better reflect the nature of technical office costs. Accordingly,
2024 adjusted unit operating costs per barrel of oil equivalent has been
updated to reflect the revised production figures.
Operational and financial summary
l Proven and probable ("2P") reserves at 31 December 2025 totalled 56.2 MMboe,
a decrease of 12.1 MMboe on end-2024, primarily due to 7.0 MMboe of production
in 2025, the sale of the Group's Sinphuhorm interest during the year and the
remainder due to technical and economic revisions across the Group.
l Production increased by 6% year-on-year to an annual record of 19,829 boe/d
(2024: 18,696 boe/d), primarily due to a full year of production from Akatara,
partially offset by the sale of Sinphuhorm and natural declines and downtime
at the Group's Australian and Peninsular Malaysia Assets ("PenMal Assets")
¡ On an underlying basis (excluding the Sinphuhorm interest), production
increased by 14% during the year.
l Total sales volumes of oil, gas, LPG and condensate increased by 23% in 2025
to 6.5 MMboe (2024: 5.3 MMboe), reflecting the increase in full year
production and lifting schedules.
l Revenue increased by 3% to US$408.1 million (2024: US$395.0 million) due to
a full year increase in Akatara revenue of US$75.4 million and a US$29.6
million net year-on-year change in hedging offset by a US$92.0 million
year-on-year decline in oil sales across Montara, Stag, CWLH, and PenMal,
reflecting both lower production levels and reduced realized prices.
l The average realized oil price before hedging decreased 13% to US$74.42/bbl
in 2025 (2024: US$85.21/bbl), primarily reflecting movements in underlying
benchmark oil prices. The average realized price premium for 2025 was
US$3.17/bbl (2024: US$3.76/bbl).
l Production costs of US$232.7 million were 19% lower year-on-year (2024:
US$286.9 million). A full-year of Akatara production added US$9.3 million,
which was offset by reductions at Montara (US$1.8 million) due to lower
operating cost and R&M activity, the PenMal Assets (US$20.9 million) due
to lower Puteri Cluster costs, inventory movements, R&M and logistics,
CWLH (US$20.7 million) due to purchase price accounting effects in 2024, and
Stag (US$20.1 million) due to lower R&M and workovers.
¡ Adjusted unit operating costs decreased by 21% in 2025 to US$28.02/boe
(2024: US$35.28/boe), driven by a higher weighting of lower‑cost Akatara
production in the portfolio.
l Adjusted EBITDAX for 2025 increased by 20% to US$153.0 million, up from
US$127.9 million in 2024, driven by the factors set out above.
l As at 31 December 2025, pre-tax impairment of oil and gas properties
amounted to US$126.0 million in 2025 (2024: US$Nil). The after‑tax impact of
this impairment was US$88.2 million in 2025 (2024: US$Nil), comprising US$45.3
million in respect of Stag and US$42.9 million relating to Montara.
l 2025 loss after tax of US$105.5 million (2024: US$44.1 million loss after
tax), driven by the non-cash impairment.
l 2025 operating cash flow before movements in working capital of US$123.6
million, an increase of 75% compared to 2024 (US$70.5 million).
l 2025 capital expenditure of US$92.8 million increased 25% year-on-year
(2024: US$74.5 million), primarily due to the drilling of Skua-11ST well at
Montara.
l Net debt of US$89.1 million at 2025 year-end (2024 year-end: US$104.8
million), reflecting US$150.0 million drawn under the RBL Facility(( 11
(#_ftn11) )) and total cash and cash equivalents (including restricted cash)
of US$60.9 million.
OPERATING SAFELY AND RESPONSIBLY
2025 2024
Total hours without a life altering event 1,951,707 5,418,258
Total lost-time injury rate 0.0 0.18
The Group continued its strong safety performance in 2025, the Group reported
zero life altering events, zero lost time injuries, no significant impacts to
the environment and a 61% year-on-year reduction in recordable injuries.
During the year the organization received two enforcement directives in
Australia and there were two losses of primary containment Tier 1 process
safety incidents, neither of which resulted in injury, environmental harm or
property damage. The reduction in manhours was a result of the Akatara
construction and commissioning coming to an end in 2024.
During 2025, the Group focused on several Health, Safety, and Environment
("HSE") initiatives, including the introduction of the International
Association of Oil and Gas Procedures ("IOGP") Process Safety Fundamentals
("PSF"). The ten IOGP PSF rules were developed from decades of experience
across the global oil and gas industry and focus on areas where small lapses
can lead to major accident events. Other key activities during the period
included updating the Group HSE Policy, which now formally incorporates
security matters and has been renamed as the Health, Safety, Security and
Environment ("HSSE") Policy and ongoing risk management across the Group's
operations.
In August a Prohibition Notice was issued in connection with corroded N(2)
cylinders on the Montara FPSO, which are part of the firefighting foam system.
Jadestone proactively shut down production at Montara and replaced eight
cylinders, restarting the facility four days later. There was no loss of
containment or injury associated with this Prohibition notice.
In September 2025, NOPSEMA issued a General Direction requiring Jadestone to
revise its policies and approach to the hull integrity management of the
Montara Venture FPSO, and commission an independent review and verification
that the Group's hull integrity management approach aligns with common
industry practice and sound integrity management principles. Four tanks remain
under the 2022 Prohibition Notice, with expected an return to service date in
the fourth quarter of 2026 for all four tanks. The Level 4 regulatory
investigation into the 2022 Montara 2 Centre Crude Oil Tank leak of oil to sea
was closed during 2025 without any findings or penalties.
There were eight high potential incidents in 2025. While none of these events
had a material impact to health, safety or the environment in which we
operate, formal investigations were conducted to ensure learning was captured
to prevent recurrence. These learnings were shared across the Group and
industry as applicable.
There were two Tier 1 process safety events recorded in 2025. During LPG truck
loading at Akatara, a LPG loading hose detached resulting in a leak of LPG.
The Akatara Gas Processing Facility ("AGPF") was shut down to avoid any
escalation. There were no injuries, and an engineering solution in the form of
loading arms was subsequently fitted to the loading station. At Montara,
there was an observed gas leak at the Swift North 1 well, with an
investigation revealing a secondary barrier failure in the 9 5/8" casing,
resulting in a release of gas that is reinjected into the well to help oil
recovery. The well remains shut in with an intact primary barrier, and there
was no loss of reservoir fluids.
In response to several Tier III loss of primary containment events the interim
COO commissioned a focus group to understand the effectiveness of asset
integrity and associated systems across the Group. An action plan was
developed to cover off on findings including setting up Networks of Excellence
for asset integrity and process safety, independent peer reviews with SMEs
from each country, Group dashboards to ensure visibility of integrity
management programs and improved assurance and auditing.
To drive improvements in key areas, a line-of-sight tool was developed in
Australia. The tool includes but is not limited to maintenance and
reliability, hull/structural/process/well integrity, production, and HSE
performance. The tool is live, interactive and visible to the workforce via
Jadestone's internal intranet and is displayed in multiple locations. The tool
has already proven effective in highlighting several areas that require extra
focus to reduce risk exposures and additionally identify areas where systems
and practices were effectively managed. Following its successful use in the
Group's Australia operations, a version of the tool is being developed for the
Group's Indonesia and Malaysia operations.
Jadestone's position is that, where possible, future oil and gas demand should
be met through maximizing reserves and production from existing fields and
discoveries, rather than exploring for and developing new sources of supply.
This key pillar of the Group's strategy reflects the increasing focus on
reinvestment in existing fields, as highlighted in the updated Net Zero
Emissions scenario in the World Energy Outlook 2025. Jadestone's core
capabilities of mature asset management and gas resource development across
the Asia-Pacific region highlight the relevance of the Group's strategy in the
energy transition.
Jadestone continues to make efforts to mitigate its environmental impact to as
low as reasonably possible. The Group's gross Scope 1 GHG emissions during
2025 totaled 547 kilo tonnes CO(2)-e (2024: 587 kilo tonnes). Lower than plan
GHGs were attributed to a combination of unexpected downtime in Australia,
revised GHG estimation methodologies as well as lower fuel gas use trend at
one of the Group's Malaysia assets.
As a key enabler of the Group's Net Zero GHG emissions pledge by 2040, the
Group has committed to interim net GHG emissions reduction targets from its
operated assets of 20% by 2026 and 45% by 2030 (from 2021 levels). The 2026
interim target will be achieved through direct GHG mitigation measures as well
as reliance on carbon credits within the regulatory schemes of Jadestone's
operating regions. A key element of the GHG mitigation plan is the upgrade of
the re-injection compressor on the Montara Venture FPSO. The upgrade, which is
being executed in 2026, is designed to reduce flaring-related GHG emissions,
whilst also allowing for increased oil production.
GOVERNANCE
During the year, the Board and executive management refresh was completed, a
process commenced in late 2024. On 16 January 2025, David Mendelson was
appointed as an independent Non-Executive Director, further broadening the
Board's range of expertise. Mr. Mendelson currently Chairs the Remuneration
Committee and participates on the Audit Committee; Governance and Nomination
Committee; and Health, Safety, Environment and Climate Committee.
Cedric Fontenit stepped down as an independent Non-Executive Director with
effect from 20 January 2025, following an orderly transition. Jenifer Thien,
independent Non-Executive Director, retired from the Board on 20 June 2025 and
did not seek re-election at the 2025 AGM.
Following the Board's decision, Dr. Adel Chaouch assumed the CEO's
responsibilities in his capacity as Executive Chairman from 5 December 2024,
to provide continuity of leadership while the search for a permanent CEO
progressed. The Board was subsequently pleased to welcome Thomas Mitchell
Little, appointed Chief Executive Officer on 1 June 2025 and to the Board as
an Executive Director on 26 June 2025, bringing over three decades of upstream
operational and senior leadership experience, including extensive
international and Asia-Pacific exposure gained during his tenure with Marathon
Oil.
Joanne Williams performed the duties of Chief Operating Officer on a temporary
basis from 5 December 2024 until 30 September 2025. Dr. Chaouch's role as an
Executive Chairman was extended on 5 December 2025 for a one-year term, with a
focus on strategic initiatives to unlock and communicate the Company's
underlying value. Dr. Chaouch's role will revert to Non-Executive Chairman
no later than 4 December 2026.
The Board recognizes the importance of effective corporate governance in
supporting the Group's long-term success and remains fully committed to
maintaining high standards of governance. Following the revision of the QCA
Corporate Governance Code in 2023, the Board adopted the QCA Corporate
Governance Code 2023 with effect from the financial year commencing 1 January
2025. The annual statement setting out how Jadestone applied the QCA Code
during the year is contained within the 2025 Annual Report.
OPERATIONAL REVIEW
INDONESIA
Akatara field, Lemang PSC (100% working interest 12 (#_ftn12) , operator)
Akatara production during 2025 averaged 6,067 boe/d, compared to 977 boe/d in
2024, when the asset was brought onstream in the second half of 2024 following
successful commissioning. Total production in 2025 was split roughly equally
between gas and liquids (LPG and condensate). A total of 6.8 Bscf of Akatara
gas was sold in 2025 at a weighted average gas price of US$5.99/Mscf, while
1.1 MMbbls of LPG and condensate were sold at a weighted average price of
US$45.89/bbl, reflecting pricing benchmarks less transportation costs.
The Akatara Gas Processing Facility, which processes reservoir gas from the
Akatara field into sales gas, LPG and condensate, delivered an excellent
performance in 2025, its first full year of operation. Annual uptime,
excluding planned downtime, at 94.4% was ahead of expectations.
The HSE performance at Akatara remains highly impressive, with over 9.3
million manhours having been worked to date in both the development and
production phase without a lost-time injury.
The scheduled annual shutdown at Akatara was successfully executed in May
2025, with a focus on addressing outstanding work scopes to close out the EPCI
contract and implementing upgrades to enhance the reliability and throughput
of the AGPF and its ability to recover from process upsets.
The first phase of the debottlenecking project to increase the AGPF's capacity
was also executed during the May 2025 shutdown, accelerating 0.8 MMboe of
reserves and increasing the technical potential of the plant to 6,800 boe/d.
The second phase of the debottlenecking project would involve re-routing the
fuel gas source point at the AGPF upstream, optimizing the flow of
hydrocarbons through the plant and potentially increasing sales gas,
condensate and LPG volumes. Concept studies, engineering and value analysis
for the second phase will be undertaken in 2026, ahead of a decision to
implement the work in 2027.
The Lemang PSC carries a remaining commitment to acquire 403km(2) of 3D
seismic and drill an exploration well. Jadestone is proposing to convert the
seismic commitment into a further well due to the remaining PSC area being
insufficient to fulfill the seismic acquisition. Existing 2D seismic is
currently being reprocessed to determine potential drilling candidates.
AUSTRALIA
CWLH (33.33%, non-operator)
During 2025, Jadestone's net production from the CWLH fields averaged 3,518
bbls/d, compared to 3,711 bbls/d in 2024. Although there was a full period
contribution in 2025 from the additional 16.67% interest in the asset which
was acquired in February 2024, which was more than offset by weather-related
facilities downtime early in 2025 and scheduled downtime later in the year to
test the asset's emergency shutdown systems and procedures offset this full
year contribution. Outside these factors, CWLH's underlying performance
remained robust, achieving almost 100% uptime over the period from May to
November 2025 and producing above 4,000 bbls/d net to Jadestone for several
consecutive months during the year.
During 2025, the CWLH JV planned for a scheduled drydock of the Okha FPSO. The
FPSO went off station in March 2026, with production currently expected to
restart around end-May 2026.
The Group lifted two CWLH cargoes totaling 1.3 MMbbls in 2025, with a weighted
average realized price of US$75.57/bbl (Brent price of US$75.26/bbl and a
premium of US$0.31/bbl). This compares to an average realization of
US$82.38/bbl (Brent US$83.20/bbl and a discount of US$0.82/bbl) for the two
cargoes lifted in 2024 (Brent US$83.20/bbl and a discount of US$0.82/bbl)
MONTARA (100% working interest, operator)
The Montara fields averaged 4,281 bbls/d in 2025, compared to 5,262 bbls/d in
2024. The year-on-year decrease is primarily explained by downtime associated
with the extended drilling operations at the Skua-11 side-track well
("Skua-11ST")and also the impact of an unusual, late-season, severe weather
system offshore western Australia in April 2025 which passed directly over
Montara.
The Skua-11ST well commenced drilling in April with the dual objectives of
decommissioning the original Skua-11 well and drilling a sidetrack into the
Skua structure up-dip of the original well path. The Skua-11ST well achieved
its main aims, being the acceleration and increase in recovery of reserves
from the Skua structure, extending the economic life of Montara by one year
and reducing unit operating costs.
In September 2025, the Group received a General Direction from NOPSEMA,
Australia's offshore energy regulator, requiring that Jadestone take several
actions to restore the hull integrity of the Montara Venture FPSO by making
permanent temporary or defined life repairs and ensuring that the condition of
the FPSO did not present a risk to the safety of the facility's personnel. The
Group has complied with three of the five General Direction requirements and
there has been significant progress, and engagement with NOPSEMA on, the
remaining two.
During 2025, Jadestone continued to evaluate the potential for a development
of the Montara licenses' gas resources at the end of commercial life of the
existing oil development. Evaluation will continue throughout 2026 as concepts
are matured with input from various contractors.
An increase in available FPSO crude tank capacity in the early part of 2025
allowed for a return to Free on Board cargoes, resulting in higher lifting
parcels and a reduction in lifting related costs. In total, four cargoes
totaling 1.6 MMbbls (2024: seven cargoes of 1.9 MMbbls) were lifted from
Montara in 2025, with an average realization of US$72.21/bbl (consisting of an
average Brent price of US$69.53/bbl and average premium of US$2.68/bbl). This
compares to an average realization of US$83.68/bbl in 2024 (Brent US$80.20/bbl
and premium US$3.48/bbl).
STAG (100% working interest, operator)
Stag field production averaged 2,032 bbls/d in 2025, compared to 2,006 bbls/d
in 2024. The positive impact of workover activity and active management of
electric submersible pumps in the field's wells was offset by weather impacts
early in the year and mechanical issues in wells requiring workovers to
restore output. The Stag-48H well, one of the more productive wells in the
field, remains offline pending an engineered workover solution.
Work continues on the Stag-52H and 53H infill drilling targets to improve
payback duration and returns prior to a sanction decision on either well.
The Group sold three Stag cargoes totaling 0.7 MMbbls in 2025 (2024: three
cargoes of 0.7 MMbbls). Premiums for Stag crude remained robust, with the
average realization for 2025 sales of US$80.72/bbl (Brent US$69.73/bbl and
premium US$10.99/bbl), compared to a realized price of US$95.93/bbl in 2024
(Brent US$82.18/bbl and premium US$13.75/bbl) in 2024.
In late March 2026, the Stag field facilities were damaged by Cyclone Narelle,
a Category Five storm with sustained wind speeds in excess of 200 km/hr. The
facilities were safely demobilized and shut-in prior to the storm, ensuring
there was no release of hydrocarbons to the environment. The main storm damage
was to the field's CALM buoy, through which shuttle tankers offload crude
produced from Stag. Efforts are underway to ready the CALM buoy for tow to
shore where a full damage assessment will be undertaken to inform next steps.
MALAYSIA
PM323 PSC (60% working interest, operator)
The PM323 PSC produced an average of 2,423 bbls/d net to Jadestone's working
interest in 2025 (2024: 3,484 bbls/d). The year-on-year decrease was primarily
due to natural decline following higher production rates as a result of the
Phase 8 drilling campaign in 2023.
Further infill drilling on the East Belumut field is planned in 2026, focusing
on the undrained southwestern area of the field discovered during the 2023
drilling campaign. A two firm, one contingent, well campaign commenced in
April 2026, with first oil expected around mid-year. The Group is also
progressing an extension to the existing term of the PM323 PSC.
A total of 0.4 MMbbls (2024: 0.6 MMbbls) was lifted from the PM323 PSC during
2025, with an average realization of US$70.23/bbl (2024: US$84.30/bbl).
PM329 PSC (100% working interest, operator)
The PM329 PSC produced an average of 1,063 boe/d net to Jadestone's 70%
working interest in 2025, consisting of 849 bbls/d of oil and 1.3 MMscf/d of
gas (2024: 1,501 boe/d, consisting of 1,024 bbls/d of oil and 2.9 MMscf/d of
gas). The year-on-year decrease is due to natural decline and higher gas
reinjection levels to control water cut in the oil wells.
A total of 0.2 MMbbls of oil (2024: 0.3 MMbbls) was lifted from the PM329 PSC
in 2025, with an average realization of US$69.49/bbl (2023: US$83.89/bbl). In
addition, approximately 0.3 Bcf of gas was sold at an average realization of
US$2.14/Mscf.
Effective 1 January 2026, the Group's partner in the PM329 PSC withdrew,
increasing Jadestone's interest to 100%.
Puteri Cluster (100% working interest, operator) and PM428 PSC (60% working
interest, operator)
The Puteri Cluster PSC contains the Penara, Puteri-Padang and North Lukut
fields, assets in which Jadestone previously held a 50% non-operated interest
(through the PM318 and AAKBNLP PSCs) following the Group's entry into Malaysia
in August 2021.
The Group is continuing its technical assessment of the Puteri Cluster PSC
ahead of a decision to submit a field development and abandonment plan to
PETRONAS.
The PM428 PSC is adjacent to the PM323 and PM329 PSCs and surrounds the Puteri
Cluster PSC. The license carries a minimal financial commitment to reprocess
existing seismic and contains several prospects which, in a success case,
could be developed through existing infrastructure currently operated by
Jadestone.
VIETNAM
Block 51 (100% working interest, operator) and Block 46/07 (100% working
interest, operator) PSCs
In March 2025, the Group announced that it had submitted a field development
plan ("FDP") for the Nam Du/U Minh ("ND/UM") gas discoveries offshore
southwest Vietnam, to the industry regulator Petrovietnam, commencing the
regulatory approval process. The FDP was formally approved by the Vietnam
Government on 18 March 2026, paving the way for initial gross 2P reserve
bookings for the project of approximately 32 MMboe and for the Group to
expedite discussions with interested farm-in partners. The Gas Sales and
Purchase Agreement for the supply of gas from ND/UM was signed in April 2026.
The ND/UM FDP proposes a development concept based on an unmanned wellhead
platform located at each field, each with two production wells, tied back to a
gas processing FPSO. Gas would be exported through a 34km pipeline tied into
an existing trunkline to the Ca Mau industrial complex onshore, with a planned
plateau production rate of 80MMscf/d. The FDP sets out a phased development,
with Nam Du being brought onstream initially, accelerating first gas to the
buyer and revenues to the project partners, which will help fund the
development of U Minh during the second phase.
In September 2025, Jadestone issued the contract tenders for the leased FPSO
and the engineering, construction and installation of the wellhead platforms
and pipelines. Evaluation of the bids received in response to these tenders is
currently ongoing with Jadestone intending to award these respective contracts
during the second half of the year.
The Group continues to work with Petrovietnam to obtain a suspension of the
relinquishment obligation for the Tho Chu discovery in license block 51.
THAILAND
Sinphuhorm (9.52% working interest, non-operated)
On 16 April 2025, the Group announced that it had sold its Thailand interests,
including its stake in the Sinphuhorm gas field, to a subsidiary of PTTEP, the
Thailand national oil and gas company, for a cash consideration of US$39.4
million, with a further US$3.5 million in contingent payments depending on
future license extensions.
2025 production net to Jadestone was 445 boe/d, representing production of
1,222 boe/d up to the divestment date expressed on an annualized basis.
Reserves and resources
Total 2P Reserves 13 (#_ftn13) (net, MMboe)
Australia Malaysia 14 (#_ftn14) Indonesia(14) Thailand 15 (#_ftn15) Total Group
Opening balance, 34.1 7.4 23.0 3.8 68.3
1 January 2025
Acquisitions/(disposals) - - - (3.6) (3.6)
Technical revisions (1.2) (0.3) 0.0 - (1.5)
Production (3.6) (1.3) (2.0) (0.2) (7.0)
Ending balance, 29.3 5.9 21.0 0.0 56.2
31 December 2025
March 2026 Vietnam FDP approval - - - 32.1
As at 31 December 2025, the Group had 2P Reserves of 56.2 MMboe, representing
a decrease compared with 31 December 2024, after accounting for production in
2025. 2P reserves of 3.6 MMboe in Thailand were removed following the disposal
of the Group's interest in Sinphuhorm field in Thailand in April 2025.
Downward technical revisions were recorded in Australia, reflecting actual
reservoir performance and revised timing of infill and workover projects at
the Skua field. Minor technical revisions were also recorded in Malaysia. In
March 2026, the Group booked approximately 32.1 MMboe of 2P reserves, relating
to Nam Du/U Minh offshore Vietnam following approval of the development plan
for the fields. Of the 32.1 MMboe, 30.2 MMboe was a transfer from 2C resources
with the remainder due to technical revisions.
Sproule ERCE independently evaluated the Group's year-end 2025 reserves.
Total 2C Contingent Resources 16 (#_ftn16) (net, MMboe)
Australia Malaysia Indonesia(14) Thailand(15) Vietnam Total Group
Opening balance, 10.6 16.3 0.9 4.0 93.9 125.7
1 January 2025
Acquisitions/disposals - - - (4.0) - (4.0)
Ending balance, 10.6 16.3 0.9 0.0 93.9 121.7
31 December 2025
March 2026 Vietnam FDP approval - - - - (30.2) (30.2)
Group 2C resources as at 31 December 2025 are estimated at 121.7 MMboe, a
slight decrease of 3% year-on-year, mainly reflecting the removal of 2C
resources associated with the disposal of the Group's interest in the
Sinphuhorm field in Thailand in April 2025. Following the field development
plan approval for Nam Du / U Minh referenced above, 30.2 MMboe of Vietnam 2C
resource was transferred to 2P reserves.
FINANCIAL REVIEW
The following table provides select financial information of the Group, which
was derived from, and should be read in conjunction with, the consolidated
financial statements for the year ended 31 December 2025.
US$'000 except where indicated 2025 2024
Production, boe/day 17 (#_ftn17) 19,829 18,696
Oil sales volume, barrels (bbls) 4,230,397 4,764,875
Realized oil price per barrel of (US$/bbl) 18 (#_ftn18) 74.42 85.21
Gas sales volume, thousand standard cubic feet (Mscf) 7,052,210 2,216,652
Realized gas price per thousand standard cubic feet 5.83 3.91
(US$/Mscf)
LPG and condensate sales volume, barrels (bbls) 1,085,482 150,401
Realized LPG and condensate price per barrel (US$/bbl) 45.89 56.69
Revenue 19 (#_ftn19) 408,060 395,036
Production costs (232,660) (286,908) 20 (#_ftn20)
Impairment of assets (before tax effects) 21 (#_ftn21) (126,040) -
Adjusted unit operating costs per barrel of oil equivalent 28.02 35.284
(US$/boe) 22 (#_ftn22)
Adjusted EBITDAX(6) 152,963 127,895
Unit depletion, depreciation and amortization (US$/boe) 11.82 12.45
Loss before tax (133,673) (43,435)
Loss after tax (110,747) (44,141)
Loss per ordinary share: basic and diluted (US$) (0.20) (0.08)
Operating cash flows before movement in working capital 123,637 70,526
Capital expenditure 92,807 74,459
Net debt at 31 December(6) (89,084) (104,774)
Benchmark commodity price and realized price
The average realized price decreased 13% in 2025 to US$74.42/bbl (2024:
US$85.21/bbl), primarily reflecting movements in underlying benchmark oil
prices, with the average realized Brent price reducing by 13% to US$71.25/bbl
in 2025 (2024:US$81.45/bbl). The average premium reduced by 16% to US$3.17/bbl
(2024: US$3.76/bbl), reflecting the move in the underlying price.
Production and liftings
Production for 2025 was 19,829 boe/d, an increase of 1,133 boe/d compared to
18,696 boe/d in 2024.
The increase was driven by the following key factors:
l Akatara added 5,090 boe/d in its first full year of production, with average
production in 2025 of 6,067 boe/d compared to annualized production rate of
977 boe/d in 2024 following first gas on 31 July 2024.
l Stag production in 2025 increased by 26 bbls/d to 2,032 bbls/d (2024: 2,006
bbl/d).
l PenMal Assets production decreased by 1,499 boe/d to 3,486 boe/d in 2025
(2024: 4,985 boe/d), primarily due to natural decline following higher
production rates as a result of the Phase 8 drilling campaign in 2023 and
operational issues that reduced output.
l The sale of the Group's interest in Sinphuhorm reduced production by 1,310
boe/d to 445 boe/d on an annualized basis (2024: 1,755 boe/d).
l Montara's production decreased by 982 bbls/d to 4,281 bbls/d (2024: 5,262
bbls/d). Incremental production from the Skua-11ST well was offset by extended
downtime during the drilling program and reduced water tank storage capacity
in the second half of the year due to inspection activities.
l CWLH production was reduced by 193 bbls/d to 3,518 bbls/d (2024: 3,711
bbls/d) due to higher than anticipated weather-related downtime.
In 2025, crude oil liftings declined 11% to 4.2 MMbbls (2024: 4.8 MMbbls) due
to lower oil production at Montara, PenMal and CWLH.
In 2025, gas sales increased by 222% to 7.1 Bscf, due to a full year of
production at Akatara (2024: 2.2 Bscf).
Akatara condensate and LPG liftings totalled 1.1 MMbbls in 2025 (2024: 150,401
bbls).
Revenue
The Group generated net revenue of US$408.1 million in 2025, an annual
increase of 3% (2024: US$395.0 million). 2025 revenue comprised commodity
sales of US$405.8 million (2024: US$422.5 million) and a hedging gain of
US$2.2 million (2024: hedging charge of US$27.4 million).
The net annual increase of US$13.1 million was due to:
l Akatara revenues increased by US$75.4 million to US$90.3 million in 2025
(2024: US$14.9 million), reflecting the impact of a full year of production in
2025.
l Lower realized oil prices reduced sales revenues by US$51.4 million.
l Lower combined sales volumes from Montara, Stag, PenMal and CWLH reduced
aggregate revenues by US$39.8 million.
l The hedging impact on revenue improved by US$29.6 million, driven by
commodity swap contracts at a weighted average hedging price of US$69.65/bbl.
Production costs
Production costs decreased by US$54.2 million or 19% in 2025 to US$232.7
million (2024: US$286.9 million reclassified). The year-on-year movement was
predominately due to the following factors:
l PenMal Assets production costs were US$20.9 million lower, driven by a
US$5.2 million reduction in Puteri Cluster costs, as only standby costs were
incurred compared with operating costs in 2024; US$4.7 million lower inventory
movements; US$4.2 million lower activity‑based other repairs and
maintenance; US$3.8 million lower supplementary payments due to reduced
realized prices and production volumes; and US$2.9 million in logistics
savings from a support vessel cost sharing agreement.
l CWLH production costs were US$20.7 million lower, primarily due to one-off
technical accounting impacts in 2024 following the acquisition of an
additional 16.67% interest in February 2024. Production costs in 2025 reflect
a normalized expenditure level.
l Stag production costs were US$20.1 million lower, driven by US$8.3 million
lower workover activity, US$7.2 million reduced activity-based other repairs
and maintenance, and a US$4.6 million net reduction in tanker rates, crude
consumption, and inventory movements.
l Montara production costs were US$1.8 million lower due to lower shuttle
tanker usage (extra storage vessels used in 2024) and reduced chemical
consumption during the 2025 drilling‑related shutdown this was partially
offset by crude lifting timing impact of US$4.3 million.
l Akatara costs increased US$9.3 million, reflecting a full year of production
in 2025.
The adjusted unit operating cost per barrel of oil equivalent for 2025 was
US$28.02/boe (2024: US$35.28/boe), primarily driven by a change in the
production mix. The 2025 portfolio reflected a higher proportion of
lower‑cost volumes from Akatara, offsetting the reduced contribution from
Stag and Montara. Please refer to the non-IFRS measures section later in this
document for the calculation of adjusted unit operating cost per barrel of oil
equivalent.
Depletion, depreciation and amortization ("DD&A")
DD&A expenses increased by US$7.1 million to US$99.5 million in 2025
(2024: US$91.4 million). The year‑on‑year increase was primarily driven by
Akatara DD&A charges of US$14.3 million, offset by lower DD&A expenses
at Montara, PenMal Assets and CWLH, consistent with reduced production from
those assets. The weighted average depletion unit rate decreased to
US$11.82/boe (2024: US$12.45/boe), reflecting a shift in the production mix
from higher unit DD&A Australian assets to lower unit DD&A production
at Akatara.
In 2025, the Group's right‑of‑use asset depreciation decreased by US$3.9
million to US$12.3 million (2024: US$16.2 million). The reduction was
primarily attributable to the lower level of production from Montara during
the year, with the asset holding the majority of the Group's material leases.
Administrative staff costs
Administrative staff costs decreased US$0.8 million to US$23.8 million (2024:
US$24.6 million), reflecting a net US$1.0 million lower severance payments in
2025 compared to 2024. The average onshore headcount for 2025 was 265,
compared to 252 in 2024. The share-based payment reserve increased by US$0.9
million, reflecting the grant of share-based long term incentive awards during
2025.
Other expenses
Other expenses increased US$25.9 million in 2025 to US$49.7 million (2024:
US$23.8 million reclassified), predominately due to:
l Plug and abandonment expenses written off in 2025 totalled US$18.5 million
(2024: US$Nil), relating to the abandonment of the original Skua‑11 well
during the Skua‑11ST drilling campaign.
l Assets written off increased US$6.9 million to US$8.7 million in 2025
(2024: US$1.8 million), primarily due to the write‑off of the original
Skua‑11 well after it was plugged and abandoned following the Skua‑11ST
drilling.
l The allowance for slow‑moving materials and spares decreased US$0.6
million to US$1.1 million (2024: US$1.7 million). Inventory disposal
decreased US$0.3 million in 2025 year-on-year.
Finance costs
Finance costs in 2025 were US$52.9 million (2024: US$45.1 million), with the
increase of US$7.8 million predominately due to:
l Accretion expenses for the asset retirement obligation ("ARO") increased by
US$5.7 million to US$28.2 million in 2025 (2024: US$22.5 million),
primarily due to changes in underlying assumptions and the unwinding of timing
differences.
l Interest on the RBL Facility was higher by US$2.5 million to US$18.9 million
in 2025 (2024: US$ 16.4 million). In 2024 US$5.1 million of interest was
capitalized for the Akatara development, whereas no interest was capitalized
in 2025. This was partly offset by a US$2.6 million reduction in 2025 interest
expense due to borrowings reducing by US$50.0 million during the year.
l The accretion expense on the Akatara long‑term VAT receivable decreased by
US$1.3 million, falling to credit US$1.2 million in 2025 driven by the fair
value adjustment.
l Upfront fees and interest associated with the Working Capital Facility and
other financing facilities decreased by US$0.9 million to US$1.5 million in
2025 (2024: US$2.4 million).
l Lease accretion reduced by US$1.4 million in 2025 to US$1.1 million (2024:
US$2.5 million) following the expiry and renegotiation of several leases.
l Interest expense of US$3.7 million was recognized in 2025 (2024: US$Nil)
following an Australian tax ruling in respect of prior year tax claims
relating to the H6 well drilled in 2021. The Group is in the process of
appealing the ruling.
Other income
The Group generated US$40.1 million of other income in 2025 (2024:US$29.6
million), an increase of US$10.5 million predominately due to:
l The Sinphuhorm disposal in April 2025 resulted in a net gain of
US$17.5 million.
l Foreign exchange gains and derivative revaluation gains increased by
US$1.0 million, arising from US$0.9 million in 2024 to US$1.9 million in
2025. In addition, interest bearing accounts and fixed deposit placements
generated an extra US$0.1 million of interest income.
l Gains of US$2.1 million were recognized for Montara and Stag due to the
reversal of expenses eligible for GST inputs tax credits.
l Revisions to the underlying assumptions of the ARO for PenMal assets
resulted in a gain of US$3.7 million recognized in other income (2024: US$2.8
million). No revisions were recognized for CWLH assets in 2025 (2024: US$11.0
million), resulting in a net decrease of US$10.1 million in the ARO reversal
items in profit or loss.
Other financial gains
Other financial gains reduced by US$1.7 million to US$0.9 million in 2025
(2024: US$2.6 million), primarily due to a lower fair value gain on
revaluation of the warrant liability, which is measured at fair value at each
reporting date.
In 2024, the Group recognized a gain of US$2.6 million following a significant
reduction in the warrant liability from US$3.5 million to US$0.9 million. In
contrast, the gain recognized in 2025 was US$0.9 million, arising from a
smaller reduction in the liability from US$0.9 million to US$2,651.
Accordingly, the US$1.7 million decrease represents the lower revaluation gain
recognized in the current year compared to the prior year.
Share of result of associates
The Group recognized its share of profits from its interest in the Sinphuhorm
field prior to disposal in April 2025, amounting to US$1.8 million (2024:
US$1.5 million).
Impairment
A pre-tax impairment charge of US$126.0 million was recognized in 2025 (2024:
US$Nil). The charge relates to the impairment of oil and gas properties at
Montara and Stag, amounting to US$61.2 million and US$64.8 million,
respectively. After accounting for the associated deferred tax effect, the
total post-tax impairment recognized was US$88.2 million.
The impairment resulted from the Group's annual impairment assessment, which
concluded that the value in use ("VIU") of Stag and Montara was lower than
their respective carrying values. The VIU was determined using an after‑tax
discount rate of 10.0%.
Taxation
The Group recorded a tax credit of US$22.9 million in 2025, compared to a tax
expense of US$0.7 million in 2024, reflecting the Group financial operating
loss for the year and deferred tax movements.
The Group reported a loss before tax of US$133.7 million for 2025 (2024:
US$43.4 million loss). Applying the expected weighted average effective tax
rate of 39% (2024: 35%) would imply a theoretical tax credit of US$52.1
million. The actual tax outcome differs from this figure due to several asset
and country specific tax impacts.
The effect of different tax rates in loss‑making jurisdictions resulted in a
US$12.4 million increase in the tax credit in 2025, compared to a US$5.0
million tax charge in 2024. This reflects a change in the geographic mix of
profitability and losses, particularly in jurisdictions with lower statutory
tax rates or ring‑fenced tax PSC regimes.
US$21.8 million of deferred Petroleum Resource Rent Tax ("PRRT") asset was
released and derecognized in 2025 (2024: utilization of US$10.0 million) which
reflects the nature of PRRT and the timing of deductible expenditures. The
movements in both years are predominantly attributable to deferred tax
adjustments, arising from the reversal of previously recognized deferred PRRT
balances that are no longer considered recoverable. In addition, the Group
recognized a US$1.7 million PRRT tax refund in 2024, which did not recur in
2025.
The tax effect of non-deductible expenses was US$3.5 million in the year
(2024: US$ 0.8 million), largely arising from costs that are permanently
non‑deductible including certain decommissioning related costs and corporate
overheads.
Income not subject to tax gave rise to a tax credit in 2025 of US$15.1 million
(2024: US$1.9 million) predominately reflecting Indonesia asset cost recovery
pools in excess of operating income and corporate gains not subject to tax.
Deferred tax balances not recognized in 2025 of US$9.8 million (2024: US$12.0
million) predominately relates to ARO obligations that are not expected to be
recoverable as decommissioning commences at the end of the assets economic
life and corporate losses due to insufficient future profits.
An adjustment in respect of prior years of US$2.8 million tax credit was
recognized in 2025 (2024: US$0.8 million), mainly related to finalization of
prior-year tax filings and updated assessments.
US$'000 2025 2024
US$'000 US$'000
( ) ( ) ( )
Loss before tax (133,673) (43,435)
Expected effective tax rate 39% 35%
Tax at the country level effective rate (52,131) (15,335)
Effect of different tax rates in loss making jurisdictions 12,395 5,011
Malaysia PITA tax losses on non-operated PSCs - 8,275
Derecognition/(recognition) of deferred PRRT credits 21,817 (10,031)
Utilization of previously unrecognized tax (392) -
PRRT tax refund - (1,700)
Non-deductible expenses 3,408 839
Income not subject to tax (15,068) (1,897)
Deferred tax permanent differences - 5,473
PRRT permanent differences - (1,149)
Deferred tax asset not recognized 9,827 12,049
Adjustment in respect to prior years (2,782) (829)
Tax (credit)/expense for the year (22,926) 706
RECONCILIATION OF CASH
US$'000 2025 2024
Cash and cash equivalents at the beginning of year 95,226 153,404
Revenue 408,060 395,036
Other operating income 23 (#_ftn23) 10,938 6,889
Production costs (232,660) (276,969)
Administrative staff costs(1) (22,469) (34,016)
General and administrative expenses(1) (40,232) (20,414)
Operating cash flows before movements in working 123,637 70,526
capital
Movement in working capital (40,659) 10,491
Placement of decommissioning trust fund for CWLH Assets - (83,773)
Net tax refunded/(paid) 8,408 (27,907)
Investing activities
Purchases of intangible exploration assets, oil and gas (82,974) (50,510)
properties, and plant and equipment 24 (#_ftn24)
Proceeds from the sale of Sinphuhorm interest 39,359 -
Dividends received from associate - 8,660
Cash received on acquisition of CWLH interest - 5,236
Other investing activities 7,645 7,492
Financing activities
Repayment of lease liabilities (16,206) (18,985)
Total drawdown of borrowings - 43,000
Repayment of borrowings (50,000) -
Repayment of costs and interest on borrowings (17,737) (19,086)
Other financing activities (5,783) (3,322)
Total cash and cash equivalent at the end of year 60,916 95,226
NON-IFRS MEASURES
The Group uses certain performance measures that are not specifically defined
under IFRS, or other generally accepted accounting principles. These non-IFRS
measures comprise adjusted unit operating cost per barrel of oil equivalent
(adjusted opex/boe), adjusted EBITDAX, outstanding debt, and net debt.
The following notes describe why the Group has selected these non-IFRS
measures.
Adjusted unit operating costs per barrel of oil equivalent (adjusted opex/boe)
Adjusted opex/boe is a non-IFRS measure used to monitor the Group's operating
cost efficiency, as it measures operating costs to extract hydrocarbons from
the Group's producing reservoirs on a unit basis.
Adjusted opex/boe is based on total production cost and incorporates lease
payments linked to operational activities, net of any income derived from
those right-of-use assets involved in production. The calculation excludes
factors such as oil inventories movement, underlift/overlift adjustments,
inventory write-downs, workovers, non-recurring repair and maintenance
expenses, transportation costs, supplementary payments and royalties, expenses
related to non-operating assets and DD&A. These adjustments aim to ensure
better comparability between periods.
The adjusted production costs are then divided by total produced barrels of
oil equivalent for the prevailing period to determine the unit operating cost
per barrel of oil equivalent.
US$'000 except where indicated 2025 2024
Production costs (reported) 232,660 286,908 25 (#_ftn25)
Adjustments
Lease payments related to operating activity 26 (#_ftn26) 14,779 17,538
Inventories written down 27 (#_ftn27) (6,755) -
Underlift, overlift and crude inventories movement 28 (#_ftn28) 6,831 (21,411)
Workover costs 29 (#_ftn29) (11,200) (20,797)
Other income 30 (#_ftn30) (4,483) (5,731)
Non-recurring operational costs 31 (#_ftn31) - (8,840)
Non-recurring other repair and maintenance 32 (#_ftn32) (6,837) (2,850)
Transportation costs 33 (#_ftn33) (6,190) (8,451)
Supplementary payments and royalties 34 (#_ftn34) (20,596) (17,342)
PenMal non-operated assets operational costs 35 (#_ftn35) - (262)
Adjusted production costs 198,209 218,762
Total production (barrels of oil equivalent) 36 (#_ftn36) 7,075,042 6,200,334
Adjusted unit operating costs per barrel of oil equivalent 28.02 35.281
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:
US$'000 2025 2024
Revenue 408,060 395,036
Production costs (232,660) (286,908) 37 (#_ftn37)
Administrative staff costs (23,781) (24,606)1
Other expenses (49,669) (23,737)1
Allowance for expected credit losses (105) (457)
Impairment of oil and gas properties (126,040) -
Share of results of associate accounted for using the equity method 1,849 1,553
Other income, excluding interest income 32,504 22,122
Other financial gains 928 2,611
Unadjusted EBITDAX 11,086 85,614
Non-recurring
Net (gain)/loss from oil price and foreign exchange derivatives (2,220) 27,417
Non-recurring opex 38 (#_ftn38) 6,837 11,952
Oil and gas properties written off 8,664 1,423
Impairment of oil and gas properties 126,040 -
Abandonment expenses 18,524 -
Net gain on disposal of an associate (17,518) -
Others 39 (#_ftn39) 1,550 1,489
141,877 42,281
Adjusted EBITDAX 152,963 127,895
( )
Net debt
Net debt is a non-IFRS measure which does not have a standardized definition
prescribed by IFRS. Management uses this measure to analyze the net borrowing
position of the Group.
US$'000 2025 2024
Borrowings (principal sum) (150,000) (200,000)
Cash and cash equivalents 60,916 95,226
Net debt (89,084) (104,774)
Net debt is defined as the sum of cash and cash equivalents and restricted
cash, less the outstanding principal sum of borrowings.
Consolidated Statement of Profit or Loss and Other Comprehensive Income
for the year ended 31 December 2025
2025 2024
Notes US$'000 US$'000
Consolidated statement of profit or loss
Revenue 5 408,060 395,036
Production costs 6 (232,660) (286,908)
Depletion, depreciation and amortization 7 (99,545) (91,407)
Administrative staff costs 8 (23,781) (24,606)
Other expenses 11 (49,669) (23,737)
Allowance for expected credit losses 11 (105) (457)
Impairment of oil and gas properties 13 (126,040) -
Share of results of associate accounted for using the equity method 24 1,849 1,553
Other income 14 40,149 29,614
Finance costs 15 (52,859) (45,134)
Other financial gains 16 928 2,611
Loss before tax (133,673) (43,435)
Income tax credit/(expense) 17 22,926 (706)
Loss for the year (110,747) (44,141)
Loss per ordinary share
Basic and diluted (US$) 18 (0.20) (0.08)
Consolidated statement of other comprehensive income
Loss for the year (110,747) (44,141)
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
Gain/(loss) on unrealized cash flow hedges 35 18,866 (14,849)
Hedging (gain)/loss reclassified to profit or loss 5, 35 (2,220) 27,417
16,646 12,568
Tax expense relating to components of other 17 (4,994) (3,770)
comprehensive income
Other comprehensive income 11,652 8,798
Total comprehensive loss for the year (99,095) (35,343)
Total comprehensive loss is attributable to the equity holders of the parent.
Consolidated Statement of Financial Position as at 31 December 2025
31 December 31 December
Notes 2025 2024
US$'000 US$'000
Assets
Non-current assets
Intangible exploration assets 20 91,620 91,323
Oil and gas properties 21 305,566 422,239
Plant and equipment 22 10,503 10,591
Right-of-use assets 23 43,349 16,111
Investment in associate 24 - 19,544
Other receivables 28 273,615 274,124
Deferred tax assets 26 20,606 44,898
Cash and cash equivalents 29 310 888
Total non-current assets 745,569 879,718
Current assets
Inventories 27 41,951 44,602
Trade and other receivables 28 67,469 55,044
Derivative financial instruments 41 9,331 -
Tax recoverable 11,142 13,863
Cash and cash equivalents 29 60,606 94,338
Total current assets 190,499 207,847
Total assets 936,068 1,087,565
Equity and liabilities
Equity
Capital and reserves
Share capital 30 458 457
Share premium account 30 52,505 52,176
Merger reserve 32 146,270 146,270
Share-based payments reserve 33 28,712 27,730
Capital redemption reserve 34 24 24
Hedging reserve 35 6,319 (5,333)
Accumulated losses (313,237) (202,490)
Total equity (78,949) 18,834
Consolidated Statement of Financial Position as at 31 December 2025 (con't)
31 December 31 December
2025 2024
Notes US$'000 US$'000
Non-current liabilities
Provisions 36 698,298 664,951
Borrowings 37 40,288 122,978
Lease liabilities 38 33,586 3,486
Other payables 40 20,703 17,282
Deferred tax liabilities 26 18,650 59,620
Total non-current liabilities 811,525 868,317
Current liabilities
Borrowings 37 111,093 77,212
Lease liabilities 38 8,351 14,065
Trade and other payables 40 72,460 92,793
Derivative financial instruments 41 - 7,618
Warrants liability 42 3 931
XXX
Provisions 36 9,244 5,542
Tax liabilities 2,341 2,253
Total current liabilities 203,492 200,414
Total liabilities 1,015,017 1,068,731
TOTAL EQUITY AND LIABILITIES
Total equity and liabilities 936,068 1,087,565
Consolidated Statement of Changes in Equity for the year ended 31 December
2025
Share premium Share-based payments reserve Capital redemption reserve
Share capital account Merger reserve US$'000 US$'000 Hedging reserve Accumulated losses
US$'000 US$'000 US$'000 US$'000 US$'000 Total
US$'000
As at 1 January 2024 456 51,827 146,270 27,673 24 (14,131) (158,349) 53,770
Loss for the year - - - - - - (44,141) (44,141)
Other comprehensive income for the year - - - - - 8,798 - 8,798
Total comprehensive income for the year - - - - - 8,798 (44,141) (35,343)
Share-based payments (Note 9) - - - 407 - - - 407
Shares issued (Note 30) 1 349 - (350) - - - -
Total transactions with owners, recognized directly in equity 1 349 - 57 - - - 407
As at 31 December 2024 457 52,176 146,270 27,730 24 (5,333) (202,490) 18,834
Consolidated Statement of Changes in Equity for the year ended 31 December
2025 (con't)
Share premium Share-based payments reserve Capital redemption reserve
Share capital account Merger reserve US$'000 US$'000 Hedging reserve Accumulated losses
US$'000 US$'000 US$'000 US$'000 US$'000 Total
US$'000
As at 1 January 2025 457 52,176 146,270 27,730 24 (5,333) (202,490) 18,834
Loss for the year - - - - - - (110,747) (110,747)
Other comprehensive income for the year - - - - - 11,652 - 11,652
Total comprehensive loss for the year - - - - - 11,652 (110,747) (99,095)
Share-based payments (Note 9) - - - 1,312 - - - 1,312
Shares issued (Note 30) 1 329 - (330) -
Total transactions with owners, recognized directly in equity 1 329 - 982 - - - 1,312
As at 31 December 2025 458 52,505 146,270 28,712 24 6,319 (313,237) (78,949)
Consolidated Statement of Cash Flows for the year ended 31 December 2025
2025 2024
Notes US$'000 US$'000
Operating activities
Loss before tax (133,673) (43,435)
Adjustments for:
Depletion, depreciation and amortization 7 99,545 91,407
Share-based payments 8 1,312 407
Allowance for slow moving inventories 11 1,072 1,670
Assets written off 11 8,664 1,775
Allowance for expected credit losses 11 105 457
Impairment of oil and gas properties 13 126,040 -
Interest income 14 (7,645) (7,492)
Reversal of provision 14 (3,679) (14,936)
Gain on the sale of associate 14 (17,518) -
Gain on hedge ineffectiveness of cash flow 14 -
hedges (303)
Unrealized foreign exchange gain (365) (297)
Finance costs 15 52,859 45,134
Other financial gains 16 (928) (2,611)
Share of results of associate 24 (1,849) (1,553)
Operating cash flows before movements in working capital 123,637 70,526
Working capital movements:
(Increase) in trade and other receivables (20,868) (63,613)
(Increase)/decrease in inventories (1,903) 29,954
(Decrease) in trade and other payables (17,888) (39,623)
Cash generated/(used in) from operations 82,978 (2,756)
Net tax received/(paid) 8,408 (27,907)
Net cash generated from/(used in) operating activities 91,386 (30,663)
Investing activities
Cash received on acquisition of additional interest of CWLH Assets 19 - 5,236
Proceeds from the sale of Sinphuhorm Asset 24 39,359 -
Payment for oil and gas properties 21 (81,148) (48,427)
Payment for plant and equipment 22 (71) (476)
Payment for intangible exploration assets 20 (1,755) (1,607)
Dividends received from associate 24 - 8,660
Interest received 14 7,645 7,492
Net cash used in investing activities (35,970) (29,122)
Consolidated Statement of Cash Flows for the year ended 31 December 2025
(con't)
2025 2024
Notes US$'000 US$'000
Financing activities
Total drawdown of borrowings 39 - 43,000
Repayment of borrowings 39 (50,000) -
Interest on borrowings paid 39 (17,737) (18,944)
Commitment fees of borrowings paid 39 - (142)
Repayment of lease liabilities 39 (16,206) (18,985)
Other interest and fees paid (5,783) (3,322)
Net cash (used in)/generated from financing activities (89,726) 1,607
Net decrease in cash and cash equivalents (34,310) (58,178)
Cash and cash equivalents at beginning of the year 95,226 153,404
Cash and cash equivalents at end of the year 29 60,916 95,226
Notes to the Consolidated Financial Statements for the year ended 31 December
2025
1. General Information
Jadestone Energy plc (the "Company" or "Jadestone") is a company incorporated
and registered in England and Wales. The Company's shares are traded on AIM
under the symbol "JSE". The Company is the ultimate parent company. The
consolidated financial statements of the Company and its subsidiaries (the
"Group") are prepared for the year ended 31 December 2025.
The financial statements are presented in United States Dollars ("US$") and
are rounded to the nearest dollar or nearest $'000.
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.
The Group's producing assets comprise the Vulcan (Montara) basin, Carnarvon
(Stag) basin and Cossack, Wanaea, Lambert, and Hermes oil fields, located
offshore Western Australia; the East Piatu, East Belumut, West Belumut and
Chermingat oil and gas fields, located in shallow water offshore Peninsular
Malaysia; and the Akatara gas, LPG and condensate field, onshore Indonesia.
The Group's development assets include the Nam Du and U Minh gas fields,
located in Block 46/07 and Block 51 in shallow water offshore southwest
Vietnam.
The Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower,
Singapore 079909. Under UK Company law, the registered office of the Company
is Level 19, The Shard, 32 London Bridge Street, London, SE1 9SG United
Kingdom.
2. New and amended standards
New and amended IFRS Accounting Standards that are effective for the current
year
In the current year, the Group has applied the following amendment to
UK-adopted IFRS Accounting Standards which is mandatorily effective for an
accounting period that begins on or after 1 January 2025. Its adoption has not
had any material impact on the disclosures or on the amounts reported in these
financial statements.
Amendments to IAS 21 The Group has adopted the amendments to IAS 21 for the first time in the
current year.
The effects of Changes in Foreign Exchanges Rates titled Lack of
Exchangeability
The amendments specify how to assess whether a currency is exchangeable, and
how to determine the exchange rate when it is not.
New and revised IFRS Accounting Standards in issue but not yet effective
At the date of authorization of these financial statements, the Group has not
applied the following new and revised IFRS Accounting Standards that have been
issued but are not yet effective:
Amendments to IFRS 9 and IFRS 7 Amendment to the Classification and Measurement of Financial Instruments
Annual improvements to IFRS Amendments to IFRS 1 First-time adoption of International Financial Reporting
Standards, IFRS 7 Financial Instruments: Disclosure and its accompanying
Guidance on implementing IFRS 7, IFRS 9 Financial Instruments, IFRS 10
Consolidated Financial Statements, and IAS 7 Statement of Cash Flows
Amendments to IFRS 9 and IFRS 7 Contracts Referencing Nature-dependent Electricity
Amendments to IFRS 19 Subsidiaries without public accountability
Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates: Translation to
Hyperinflationary Presentation Currency
IFRS 18 Presentation and Disclosures in Financial Statements
IFRS 19 Subsidiaries without Public Accountability: Disclosures
The Directors do not expect that the adoption of the standards listed above
will have a material impact on the financial statements of the Group in future
periods, except if indicated below.
IFRS 18 Presentation and Disclosures in Financial Statements
IFRS 18 replaces IAS 1, carrying forward many of the requirements in IAS 1
unchanged and complementing them with new requirements. In addition, some
paragraphs from IAS 1 have been moved to IAS 8 and IFRS 7. Furthermore, the
IASB has made minor amendments to IAS 7 and IAS 33 Earnings per Share.
IFRS 18 introduces new requirements to:
· present specified categories and defined subtotals in the statement
of profit or loss;
· provide disclosures on management-defined performance measures (MPMs)
in the notes to the financial statements;
· improve aggregation and disaggregation; and
· among other requirements
An entity is required to apply IFRS 18 for annual reporting periods beginning
on or after 1 January 2027, with earlier application permitted. The amendments
to IAS 7 and IAS 33, as well as the revised IAS 8 and IFRS 7, become effective
when an entity applies IFRS 18. IFRS 18 requires retrospective application
with specific transition provisions.
The Directors of the Company anticipate that the application of these
amendments will have an impact on the presentation and disclosure of the
Group's consolidated financial statements in future periods. The adoption of
IFRS 18 is not expected to result in significant changes to the recognition
and measurement of the Group's assets, liabilities, income and expenses. The
Group is currently assessing the detailed impact of these amendments.
3. Material accounting policies
Basis of accounting
The financial statements have been prepared on the historical cost convention
basis, except as disclosed in the accounting policies below and in accordance
with UK-adopted International Accounting Standards ("IAS") and International
Financial Reporting Standards ("IFRS") as issued by the International
Accounting Standards Board ("IASB") and in conformity with the requirements of
the Companies Act 2006 (the "Act").
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 are
satisfied that the Group has sufficient financial resources to continue
operations for the foreseeable future, being a period of at least 12 months
from the date of approval of these financial statements (the "Review Period").
On 26 March 2026, the Group successfully completed a US$200.0 million senior
secured bond with a maturity in 2031 and a 12% coupon which will be used to
repay the outstanding US$122.0 million reserve-based lending ("RBL") facility,
providing the Group with an enhanced capital structure that is simple,
flexible and aligned with its growth ambitions. The bond principal amortizes
US$50.0 million per annum from the third anniversary of the bond issue with a
final repayment of US$100.0 million at the maturity date.
On 23 March 2026, the Stag facility was demobilized due to a cyclone, in line
with the Group's standard seasonal cyclone procedures. Upon return to the
facility on 28 March 2026, storm-related damage was identified, and a repair
plan and schedule are currently being developed. An estimate of associated
downtime has been incorporated into the Group's production and operational
planning.
As at 31 December 2025, the Group had cash and cash equivalents of US$56.7
million (excluding restricted cash), together with additional available
liquidity of US$30.0 million from an undrawn working capital facility. As at
30 April 2026, the Group had cash and cash equivalents of US$111.1 million
(excluding restricted cash) and continued to have access to the undrawn
working capital facility of US$30.0 million, maturing on 31 December 2026. At
31 December 2025 the Group's total liabilities exceeded its total assets.
The refinancing of the balance sheet following the US$200 million bond in
March 2026 will reclassify borrowings of US$111.1 million at year end, to
non‑current liabilities, reflecting the five-year tenor of the bond,
amortizing after year three. The majority of the Group's non-current
liabilities are related to the Group's asset retirement obligations which do
not fall due earlier than five to ten years in the future and therefore do not
impact short-term liquidity.
The assessment undertaken incorporated updated estimates of production
performance together with associated operating costs and committed capital
expenditure. The forward-looking analysis considered anticipated production
profiles, cost inflation pressures and planned capital programs together with
the potential impact of external factors on these assumptions. In particular,
consideration was given to the increased volatility arising from geopolitical
events and disruptions to the global oil trade as a result of the conflict in
the Middle East causing macroeconomic uncertainty. These factors and the
potential impact on global commodity markets was modelled through downside oil
price sensitivity scenarios, including sustained prices below long‑term
consensus levels, to assess cash flow resilience under adverse conditions.
Taking these factors into account, management has assumed in its base case
assumptions for the Review Period a Brent oil price of US$80/bbl for the
remainder of 2026 and US$75/bbl for 2027, both of which are significantly
below current spot prices. Capital expenditure guidance for 2026 remains at
US$50 million to US$80 million, as previously disclosed, with the principal
capital expenditure relating to the drilling campaign in Malaysia.
The base case has also been subjected to further testing through a scenario
that explores the impact of the following plausible downside risks, being a
lower Brent oil price of US$65/bbl for the remainder of 2026 and for 2027,
together with additional unplanned downtime of one month each at Montara and
Akatara and a 10% increase in operating costs.
The base case and downside case indicate that the Group is able to operate as
a going concern and remain covenant compliant for 12 months from the date of
publication of its full year results.
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 for the foreseeable future. Accordingly, they have prepared
these audited consolidated financial statements on a going concern basis.
Basis of consolidation
The consolidated financial statements incorporate the financial statements of
the parent entity and entities controlled by the Group made up to 31 December
each year. Control is achieved when the Group:
· has power over the investee;
· is exposed, or has rights, to variable returns from its involvement
with the investee; and
· has the ability to use its power to affect its return.
The Group reassesses whether or not it controls an investee if facts and
circumstances indicate that there are changes to one or more of the three
elements of control listed above.
When the Group has less than a majority of the voting rights of an investee,
it considers that it has power over the investee when the voting rights are
sufficient to give it the practical ability to direct the relevant activities
of the investee unilaterally. The Group considers all relevant facts and
circumstances in assessing whether or not the Group's voting rights in an
investee are sufficient to give it power, including:
· the size of the Group's holding of voting rights relative to the size
and dispersion of holdings of the other vote holders;
· potential voting rights held by the Group, other vote holders or
other parties;
· rights arising from other contractual arrangements; and
· any additional facts and circumstances that indicate that the Group
has, or does not have, the current ability to direct the relevant activities
at the time that decisions need to be made, including voting patterns at
previous shareholders' meetings.
Consolidation of a subsidiary begins when the Group obtains control over the
subsidiary and ceases when the Group loses control of the subsidiary.
Specifically, the results of subsidiaries acquired or disposed of during the
year are included in profit or loss from the date the Group gains control
until the date when the Group ceases to control the subsidiary.
Where necessary, adjustments are made to the financial statements of
subsidiaries to bring the accounting policies used into line with the Group's
accounting policies.
All intragroup assets and liabilities, equity, income, expenses and cash flows
relating to transactions between the members of the Group are eliminated on
consolidation.
Profit or loss and each component of other comprehensive income are attributed
to the owners of the parent entity. Total comprehensive income of the
subsidiaries is attributed to the owners of the parent entity.
Changes in the Group's interests in subsidiaries that do not result in a loss
of control are accounted for as equity transactions. The carrying amount of
the Group's interests is adjusted to reflect the changes in their relative
interests in the subsidiaries.
When the Group loses control of a subsidiary, the gain or loss on disposal
recognized in profit or loss is calculated as the difference between (i) the
aggregate of the fair value of the consideration received and the fair value
of any retained interest and (ii) the previous carrying amount of the assets
(including goodwill), less liabilities of the subsidiary. All amounts
previously recognized in other comprehensive income in relation to that
subsidiary are accounted for as if the Group had directly disposed of the
related assets or liabilities of the subsidiary (i.e. reclassified to profit
or loss or transferred to another category of equity as required/permitted by
applicable IFRS Accounting Standards). The fair value of any investment
retained in the former subsidiary at the date when control is lost is regarded
as the fair value on initial recognition for subsequent accounting under IFRS
9 Financial Instruments when applicable, or the cost on initial recognition of
an investment in an associate or a joint venture.
Business combination
Acquisitions of businesses, including joint operations which are assessed to
be businesses, are accounted for using the acquisition method. The
consideration transferred in a business combination is measured at fair value,
which is calculated as the sum of the acquisition-date fair values of assets
transferred by the Group, liabilities incurred by the Group to the former
owners of the acquiree and the equity interest issued by the Group in exchange
for control of the acquiree. Acquisition-related costs are recognized in
profit or loss as incurred.
At the acquisition date, the identifiable assets acquired and the liabilities
assumed are recognized at their fair value, except that:
· deferred tax assets or liabilities, and assets or liabilities
related to employee benefit arrangements are recognized and measured in
accordance with IAS 12 Income Taxes and IAS 19 Employee Benefits respectively;
· liabilities or equity instruments related to share-based payment
transactions of the acquiree or share-based payment arrangements of the Group
entered into to replace share-based payment arrangements of the acquiree are
measured in accordance with IFRS 2 Share-based Payment at the acquisition date
(see below); and
· assets (or disposal groups) that are classified as held for sale
in accordance with IFRS 5 Non-Current Assets Held for Sale and Discontinued
Operations are measured in accordance with that standard.
Goodwill is measured as the excess of the sum of the consideration
transferred, the amount of any non-controlling interests in the acquiree, and
the fair value of the acquirer's previously held equity interest in the
acquiree, (if any) over the net of the acquisition-date amounts of the
identifiable assets acquired and the liabilities assumed. If, after
reassessment, the net of the acquisition-date amounts of the identifiable
assets acquired and liabilities assumed exceeds the sum of the consideration
transferred, the amount of any non-controlling interests in the acquiree and
the fair value of the acquirer's previously held interest in the acquiree (if
any), the excess is recognized immediately in profit or loss as a bargain
purchase gain.
When the consideration transferred by the Group in a business combination
includes a contingent consideration arrangement, the contingent consideration
is measured at its acquisition-date fair value and included as part of the
consideration transferred in a business combination. Changes in fair value of
the contingent consideration that qualify as measurement period adjustments
are adjusted retrospectively, with corresponding adjustments against goodwill.
Measurement period adjustments are adjustments that arise from additional
information obtained during the 'measurement period' (which cannot exceed one
year from the acquisition date) about facts and circumstances that existed at
the acquisition date.
The subsequent accounting for changes in the fair value of the contingent
consideration that do not qualify as measurement period adjustments depends on
how the contingent consideration is classified. Contingent consideration that
is classified as equity is not remeasured at subsequent reporting dates and
its subsequent settlement is accounted for within equity. Other contingent
consideration is remeasured to fair value at subsequent reporting dates with
changes in fair value recognized in profit or loss.
When a business combination is achieved in stages, the Group's previously held
interests in an acquired entity that is an associate or a joint venture, or a
joint operation that constitutes a business, is remeasured to its
acquisition-date fair value and the resulting gain or loss, if any, is
recognized in profit or loss. Amounts arising from interests in the acquiree
prior to the acquisition date that have previously been recognized in other
comprehensive income are reclassified to profit or loss, where such treatment
would be appropriate if that interest were disposed of.
If the initial accounting for a business combination is incomplete by the end
of the reporting period in which the combination occurs, the Group reports
provisional amounts for the items for which the accounting is incomplete.
Those provisional amounts are adjusted during the measurement period (see
above), or additional assets or liabilities are recognized, to reflect new
information obtained about facts and circumstances that existed as of the
acquisition date that, if known, would have affected the amounts recognized as
of that date.
Where an interest in a production sharing contract ("PSC") is acquired by way
of a corporate acquisition, the interest in the PSC is treated as an asset
purchase unless the acquisition of the corporate vehicle meets the definition
of a business and the requirements to be treated as a business combination.
Investment in associates and joint ventures
An associate is an entity over which the Group has significant influence and
that is neither a subsidiary nor an interest in a joint venture. Significant
influence is the power to participate in the financial and operating policy
decisions of the investee but is not control or joint control over those
policies.
A joint venture is a joint arrangement whereby the parties that have joint
control of the arrangement have rights to the net assets of the joint
arrangement. Joint control is the contractually agreed sharing of control of
an arrangement, which exists only when decisions about the relevant activities
require unanimous consent of the parties sharing control.
The results and assets and liabilities of associates or joint ventures are
incorporated in these financial statements using the equity method of
accounting.
Under the equity method, an investment in an associate or a joint venture is
recognized initially in the consolidated statement of financial position at
cost and adjusted thereafter to recognize the Group's share of the profit or
loss and other comprehensive income of the associate or joint venture. When
the Group's share of losses of an associate or a joint venture exceeds the
Group's interest in that associate or joint venture (which includes any
long-term interests that, in substance, form part of the Group's net
investment in the associate or joint venture), the Group discontinues
recognizing its share of further losses. Additional losses are recognized only
to the extent that the Group has incurred legal or constructive obligations or
made payments on behalf of the associate or joint venture.
An investment in an associate or a joint venture is accounted for using the
equity method from the date on which the investee becomes an associate or a
joint venture. On acquisition of the investment in an associate or a joint
venture, any excess of the cost of the investment over the Group's share of
the net fair value of the identifiable assets and liabilities of the investee
is recognized as goodwill, which is included within the carrying amount of the
investment. Any excess of the Group's share of the net fair value of the
identifiable assets and liabilities over the cost of the investment, after
reassessment, is recognized immediately in profit or loss in the period in
which the investment is acquired.
If there is objective evidence that the Group's net investment in an associate
or joint venture is impaired, the requirements of IAS 36 Impairment of Assets
are applied to determine whether it is necessary to recognize any impairment
loss with respect to the Group's investment. When necessary, the entire
carrying amount of the investment (including goodwill) is tested for
impairment in accordance with IAS 36 as a single asset by comparing its
recoverable amount (higher of value in use and fair value less costs of
disposal) with its carrying amount, Any impairment loss recognized is not
allocated to any asset, including goodwill that forms part of the carrying
amount of the investment. Any reversal of that impairment loss is recognized
in accordance with IAS 36 to the extent that the recoverable amount of the
investment subsequently increases.
The Group discontinues the use of the equity method from the date when the
investment ceases to be an associate or a joint venture. When the Group
retains an interest in the former associate or a joint venture and the
retained interest is a financial asset, the Group measures the retained
interest at fair value at that date and the fair value is regarded as its fair
value on initial recognition in accordance with IFRS 9. The difference between
the carrying amount of the associate or a joint venture at the date the equity
method was discontinued, and the fair value of any retained interest and any
proceeds from disposing of a part interest in the associate or a joint venture
is included in the determination of the gain or loss on disposal of the
associate or a joint venture. In addition, the Group accounts for all amounts
previously recognized in other comprehensive income in relation to that
associate on the same basis as would be required if that associate had
directly disposed of the related assets or liabilities. Therefore, if a gain
or loss previously recognized another comprehensive income by that associate
or a joint venture would be reclassified to profit or loss on the disposal of
the related assets or liabilities, the Group reclassifies the gain or loss
from equity to profit or loss (as a reclassification adjustment) when the
associate or joint venture is disposed of.
For the purposes of the Group, associates and joint ventures may include
intermediate holding entities with interests in upstream oil and gas assets.
For example, the Group's investment in APICO LLC (up to its disposal)
represented an indirect interest in producing petroleum assets, including the
Sinphuhorm gas field and other exploration and production concessions in
Thailand.
When a Group entity transacts with an associate or a joint venture of the
Group, profits and losses resulting from the transactions with the associate
or a joint venture are recognized in the Group's consolidated financial
statements only to the extent of interests in the associate or joint venture
that are not related to the Group.
The Group applies IFRS 9, including the impairment requirements, to long-term
interests in an associate or joint venture to which the equity method is not
applied and which form part of the net investment in the investee.
Furthermore, in applying IFRS 9 to long-term interests, the Group does not
take into account adjustments to their carrying amount required by IAS 28
Investments in Associates and Joint Ventures (i.e. Adjustments to the carrying
amount of long-term interests arising from the allocation of losses of the
investee or assessment of impairment in accordance with IAS 28).
Interest in joint operations
A joint operation is a joint arrangement whereby the parties that have joint
control of the arrangement have rights to the assets, and obligations for the
liabilities, relating to the arrangement. Joint control is the contractually
agreed sharing of control of an arrangement, which exists only when decisions
about the relevant activities require unanimous consent of the parties sharing
control.
When a Group entity undertakes its activities under joint operations, the
Group as a joint operator recognizes in relation to its interest in a joint
operation:
· its assets, including its share of any assets held jointly;
· its liabilities, including its share of any liabilities incurred
jointly;
· its revenue from the sale of its share of the output arising from
the joint operation;
· its share of the revenue from the sale of the output by the joint
operation; and
· its expenses, including its share of any expenses incurred
jointly.
The Group accounts for the assets, liabilities, revenue and expenses relating
to its interest in a joint operation in accordance with the IFRS standards
applicable to the particular assets, liabilities, revenues and expenses.
When the Group transacts with a joint operation in which it is a joint
operator (such as a sale or contribution of assets), the Group is considered
to be conducting the transaction with the other parties to the joint
operation, and gains and losses resulting from the transactions are recognized
in the Group's consolidated financial statements only to the extent of other
parties' interests in the joint
operation.
When a Group transacts with a joint operation in which it is a joint operator
(such as a sale of assets to the joint operation), the Group would not
recognize a profit/loss on making a purchase from a joint operation.
Changes to the Group's interest in a PSC usually require the approval of the
appropriate regulatory authority. A change in interest is recognized when:
• Approval is considered highly likely; and
• All affected parties are effectively operating under the revised
arrangement.
Where this is not the case, no change in interest is recognized and any funds
received or paid are included in the statement of financial position as
contractual deposits.
Revenue
Revenue from contracts with customers is recognized in profit or loss when
performance obligations are considered met, which is when control of the
hydrocarbons are transferred to the customer.
When (or as) a performance obligation is satisfied, the Group recognizes as
revenue the amount of consideration which it expects to be entitled to in
exchange for transferring promised goods or services. Revenue is presented
net of hedging loss as this deduction formed part of a contractual method for
determining the transaction price. The net hedging loss is reclassified to
profit or loss in the periods when the hedged item affects profit or loss, in
the same line as the recognized hedged item, in this case, revenue.
Revenue from the production of crude oil, liquified petroleum gas ("LPG"),
condensate and gas, in which the Group has an interest with other producers,
is recognized based on the Group's working interest and the terms of the
relevant production sharing contracts.
Liquids production revenue which includes oil, LPG and condensate are
recognized when the Group gives up control of the unit of production at the
delivery point agreed under the terms of the sale contract. This generally
occurs when the product is physically transferred into a vessel, pipe or other
delivery mechanism. The amount of production revenue recognized is based on
the agreed transaction price and volumes delivered. In line with the
aforementioned, revenue is recognized at a point in time when deliveries of
the liquids are transferred to customers.
Gas production revenue is meter measured based on the hydrocarbon volumes
delivered. The volumes delivered over a calendar month are invoiced based on
monthly meter readings.
The price is either fixed (gas) or linked to an agreed benchmark (high sulphur
fuel oil) in advance. This methodology is considered appropriate as it is
normal business practice under such arrangements. In line with the
aforementioned, revenue is recognized at a point in time when deliveries of
the gas are transferred to the customer.
A monthly receivable is recognized following the gas transfers in the previous
month as recognition occurs at the point of transfer. At this point, the
Group's right to consideration becomes unconditional and only the passage of
time is required before payment is due.
Leases
The Group as a lessee
The Group assesses whether a contract is or contains a lease, at inception of
the contract. The Group recognizes a right-of-use asset and a corresponding
lease liability with respect to all lease arrangements in which it is the
lessee, except for short-term leases (defined as leases with a lease term of
12 months or less and which do not contain a purchase option) and leases of
low value assets (such as tablets and personal computers, small items of
office furniture and telephones). For these leases, the Group recognizes the
lease payments as an operating expense on a straight-line basis over the term
of the lease.
The lease liability is initially measured at the present value of the lease
payments that are not paid at the commencement date, discounted by using the
rate implicit in the lease. If this rate cannot be readily determined, the
lessee uses its estimated incremental borrowing rate.
The incremental borrowing rate depends on the term, currency and start date of
the lease and is determined based on a series of inputs including: the
risk-free rate based on government bond rates; a country-specific risk
adjustment; a credit risk adjustment based on bond yields; and an
entity-specific adjustment when the risk profile of the entity that enters
into the lease is different to that of the Group and the lease does not
benefit from a guarantee from the Group.
Lease payments included in the measurement of the lease liability comprise.
· fixed lease payments (including in-substance fixed payments),
less any lease incentives receivable;
· variable lease payments that depend on an index or rate,
initially measured using the index or rate at the commencement date;
· the amount expected to be payable by the lessee under residual
value guarantees;
· the exercise price of purchase options, if the lessee is
reasonably certain to exercise the options; and
· payments of penalties for terminating the lease, if the lease
term reflects the exercise of an option to terminate the lease.
The lease liability is subsequently measured by increasing the carrying amount
to reflect interest on the lease liability (using the effective interest
method) and by reducing the carrying amount to reflect the lease payments
made.
The Group remeasures the lease liability (and makes a corresponding adjustment
to the related right-of-use asset) whenever:
· the lease term has changed or there is a significant event or
change in circumstances resulting in a change in the assessment of exercise of
a purchase option, in which case the lease liability is remeasured by
discounting the revised lease payments using a revised discount rate.
· the lease payments change due to changes in an index or rate or a
change in expected payment under a guaranteed residual value, in which cases
the lease liability is remeasured by discounting the revised lease payments
using an unchanged discount rate (unless the lease payments change is due to a
change in a floating interest rate, in which case a revised discount rate is
used.
· a lease contract is modified and the lease modification is not
accounted for as a separate lease, in which case the lease liability is
remeasured based on the lease term of the modified lease by discounting the
revised lease payments using a revised discount rate at the effective date of
the modification.
The right-of-use assets comprise the initial measurement of the corresponding
lease liability, lease payments made at or before the commencement day, less
any lease incentives received and any initial direct costs. They are
subsequently measured at cost less accumulated depreciation and impairment
losses.
Whenever the Group incurs an obligation for costs to dismantle and remove a
leased asset, restore the site on which it is located or restore the
underlying asset to the condition required by the terms and conditions of the
lease, a provision is recognized and measured under IAS 37. To the extent that
the costs relate to a right-of-use asset, the costs are included in the
related right-of-use asset, unless those costs are incurred to produce
inventories.
Right-of-use assets are depreciated over the shorter period of the lease term
and the useful life of the underlying asset. If a lease transfers ownership of
the underlying asset or the cost of the right-of-use asset reflects that the
Group expects to exercise a purchase option, the related right-of-use asset is
depreciated over the useful life of the underlying asset. The depreciation
starts at the commencement date of the lease.
The Group applies IAS 36 to determine whether a right-of-use asset is impaired
and accounts for any identified impairment loss as described in the
"Impairment of Assets" policy.
Variable rents that do not depend on an index or rate are not included in the
measurement the lease liability and the right-of-use asset. The related
payments are recognized as an expense in the period in which the event or
condition that triggers those payments occurs.
As a practical expedient, IFRS 16 Leases permits a lessee not to separate
non-lease components, and instead account for any lease and associated
non-lease components as a single arrangement. The Group has not used this
practical expedient. For contracts that contain a lease component and one or
more additional lease or non-lease components, the Group allocates the
consideration in the contract to each lease component on the basis of the
relative stand-alone price of the lease component and the aggregate
stand-alone price of the non-lease components.
Foreign currencies
The individual financial statements of each Group entity are presented in the
currency of the primary economic environment in which it operates (its
functional currency). For the purpose of the consolidated financial
statements, the results and financial position of each Group entity are
expressed in US$, which is the functional currency of the parent entity, and
the presentation currency for the consolidated financial statements.
In preparing the financial statements of the Group entities, transactions in
currencies other than the entity's functional currency are recognized at the
rates of exchange prevailing on the dates of the transactions. At each
reporting period, monetary assets and liabilities which are denominated in
foreign currencies are retranslated at the rates prevailing at that date.
Non-monetary items carried at fair value that are denominated in foreign
currencies are retranslated at the rates prevailing at the date when the fair
value was determined. Non-monetary items that are measured in terms of
historical cost in a foreign currency are not retranslated.
Exchange differences are recognized in profit or loss in the period in which
they arise except for:
· exchange differences on foreign currency borrowings relating to
assets under construction for future productive use, which are included in the
cost of those assets when they are regarded as an adjustment to interest costs
on those foreign currency borrowings;
· exchange differences on transactions entered into to hedge
certain foreign currency risks (see below under financial instruments/hedge
accounting); and
· exchange differences on monetary items receivable from or payable
to a foreign operation for which settlement is neither planned nor likely to
occur in the foreseeable future (therefore forming part of the net investment
in the foreign operation), which are recognized initially in other
comprehensive income and reclassified from equity to profit or loss on
disposal or partial disposal of the net investment.
There is no foreign currency translation reserve created at the Group level as
the functional currencies of all subsidiaries are denominated in US$.
Borrowing costs
Borrowing costs comprise interest expense, commitment fees and other financing
costs incurred in connection with the Group's RBL facility and other borrowing
arrangements. Borrowing costs are generally recognized in profit or loss using
the effective interest method, except to the extent that they are directly
attributable to the acquisition, construction or production of qualifying oil
and gas assets, in which case they are capitalized as part of the cost of
those assets until the assets are substantially ready for their intended use
or sale.
To the extent that variable rate borrowings are used to finance a qualifying
asset and are hedged in ineffective cash flow hedge of interest rate risk, the
effective portion of the derivative is recognized in other comprehensive
income and reclassified to profit or loss when the qualifying asset affects
profit or loss. To the extent that fixed rate borrowings are used to finance a
qualifying asset and are hedged in an effective fair value hedge of interest
rate risk, the capitalized borrowing costs reflect the hedged interest rate.
All other borrowing costs are recognized in the profit or loss in the period
in which they are incurred.
Retirement and termination benefit costs
Payments to defined contribution retirement benefit plans are recognized as an
expense when employees have rendered services entitling them to the
contributions. Payments made to state-managed retirement benefit plans, such
as Malaysia's Employees Provident Fund, are accounted for as payments to
defined contribution plans where the Group's obligations under the plans are
equivalent to those arising in a defined contribution retirement benefit plan.
The Group does not have any defined benefit plans.
Short-term and other long-term employee benefits
A liability is recognized for benefits accruing to employees in respect of
wages and salaries, annual leave and sick leave in the period the related
service is rendered at the undiscounted amount of the benefits expected to be
paid in exchange for that service.
Liabilities recognized in respect of short-term employee benefits are measured
at the undiscounted amount of the benefits expected to be paid in exchange for
the related service.
Liabilities recognized in respect of other long-term employee benefits are
measured at the present value of the estimated future cash outflows expected
to be made by the Group in respect of services provided by employees up to the
reporting date.
Taxation
Income tax expense represents the sum of the current tax and deferred tax.
Current tax
The current tax payable is based on taxable profit or loss for the year.
Taxable profit differs from net profit as reported in profit or loss because
it excludes items of income or expense that are taxable or deductible in other
years and it further excludes items that are never taxable or deductible. The
Group's liability for current tax is calculated using tax rates that have been
enacted or substantively enacted by the end of the reporting period.
A provision is recognized for those matters for which the tax determination is
uncertain but it is considered probable that there will be a future outflow of
funds to a tax authority. The provisions are measured at the best estimate of
the amount expected to become payable. The assessment is based on the
judgement of tax professionals within the Group supported by previous
experience in respect of such activities and in certain cases based on
specialist independent tax advice.
Petroleum resource rent tax ("PRRT")
PRRT incurred in Australia is considered for accounting purposes to be a tax
based on income. Accordingly, current and deferred PRRT expense is measured
and disclosed on the same basis as income tax.
PRRT is calculated at the rate of 40% of sales revenues less certain permitted
deductions and is tax deductible for income tax purposes. For Australian
corporate tax purposes, PRRT payment is treated as a deductible expense, while
PRRT refund is treated as an assessable income. Therefore, for the purposes
of calculating deferred tax, the PRRT tax rate is combined with the Australian
corporate tax rate of 30% to derive a combined effective tax rate of 28%.
Malaysia Petroleum Income Tax ("PITA")
PITA incurred in Malaysia is considered for accounting purposes to be a tax
based on income derived from petroleum operations. Accordingly, current and
deferred PITA expense is measured and disclosed on the same basis as income
tax.
PITA is calculated at the rate of 38% of sales revenues less certain permitted
deductions and deferred tax is calculated at the same rate.
Indonesia Corporate and Dividend Tax ("C&D")
C&D incurred in Indonesia is considered for accounting purposes to be a
tax based on income derived from petroleum operations. Accordingly, C&D
expense is measured and disclosed on the same basis as income tax.
C&D is calculated at the rate of 20% of sales revenues less certain
permitted deductions and is tax deductible for income tax purposes. For
Indonesian corporate tax purposes, C&D payment is treated as a deductible
expense. Therefore, for the purposes of calculating deferred tax, the
C&D tax rate is combined with the Indonesian corporate tax rate of 30% to
derive a combined effective tax rate of 44%.
Deferred tax
Deferred tax is the tax expected to be payable or recoverable on differences
between the carrying amounts of assets and liabilities in the financial
statements and the corresponding tax bases used in the computation of taxable
profit and is accounted for using the liability method. Deferred tax
liabilities are generally recognized for all taxable temporary differences and
deferred tax assets are recognized to the extent that it is probable that
taxable profits will be available against which deductible temporary
differences can be utilized. Such assets and liabilities are not recognized if
the temporary difference arises from the initial recognition (other than in a
business combination or for transactions that give rise to equal taxable and
deductible temporary differences) of other assets and liabilities in a
transaction that affects neither the taxable profit nor the accounting profit.
In addition, a deferred tax liability is not recognized if the temporary
difference arises from the initial recognition of goodwill.
Deferred tax liabilities are recognized for taxable temporary differences
arising on investments in subsidiaries and associates, and interests in joint
ventures, except where the Group is able to control the reversal of the
temporary difference and it is probable that the temporary difference will not
reverse in the foreseeable future. Deferred tax assets arising from deductible
temporary differences associated with such investments and interests are only
recognized to the extent that it is probable that there will be sufficient
taxable profits against which to utilize the benefits of the temporary
differences and they are expected to reverse in the foreseeable future.
The carrying amount of deferred tax assets is reviewed at each reporting date
and reduced to the extent that it is no longer probable that sufficient
taxable profits will be available to allow all or part of the asset to be
recovered.
Deferred tax is calculated at the tax rates that are expected to apply in the
period when the liability is settled or the asset is realized based on tax
laws and rates that have been enacted or substantively enacted at the
reporting date.
The measurement of deferred tax liabilities and assets reflects the tax
consequences that would follow from the manner in which the Group expects, at
the end of the reporting period, to recover or settle the carrying amount of
its assets and liabilities.
For the purposes of measuring deferred tax liabilities and deferred tax assets
for investment properties that are measured using the fair value model, the
carrying amounts of such properties are presumed to be recovered entirely
through sale, unless the presumption is rebutted. The presumption is rebutted
when the investment property is depreciable and is held within a business
model whose objective is to consume substantially all of the economic benefits
embodied in the investment property over time, rather than through sale. The
Directors reviewed the Group's investment property portfolios and concluded
that none of the Group's investment properties are held under a business model
whose objective is to consume substantially all of the economic benefits
embodied in the investment properties over time, rather than through sale.
Therefore, the Directors have determined that the 'sale' presumption set out
in the amendments to IAS 12 is not rebutted. As a result, the Group has not
recognized any deferred taxes on changes in fair value of the investment
properties as the Group is not subject to any income taxes on the fair value
changes of the investment properties on disposal.
Deferred tax assets and liabilities are offset when there is a legally
enforceable right to offset current tax assets against current tax liabilities
and when they relate to income taxes levied by the same taxation authority and
the Group intends to settle its current tax assets and liabilities on a net
basis.
Current and deferred tax for the year
Current and deferred tax are recognized in profit or loss, except when they
relate to items that are recognized in other comprehensive income or directly
in equity, in which case, the current and deferred tax are also recognized in
other comprehensive income or directly in equity respectively. Where current
tax or deferred tax arises from the initial accounting for a business
combination, the tax effect is included in the accounting for the business
combination.
Other taxes
Revenue, expenses, assets, and liabilities are recognized net of the amount of
goods and services tax ("GST") or value added tax ("VAT") except:
· When the GST/VAT incurred on a purchase of goods and services
is not recoverable from the taxation authority, in which case the GST/VAT is
recognized as part of the cost of acquisition of the asset or as part of the
expense item as applicable; and
· Receivables and payables, which are stated with the amount of
GST/VAT included.
The net amount of GST/VAT recoverable from, or payable to, the taxation
authority is included as part of receivables or payables in the consolidated
statement of financial position.
Intangible exploration and evaluation assets
The costs of exploring for and evaluating oil and gas properties, including
the costs of acquiring rights to explore, geological and geophysical studies,
exploratory drilling and directly related overheads such as directly
attributable employee remuneration, materials, fuel used, rig costs and
payments made to contractors are capitalized and classified as intangible
exploration assets ("E&E assets"). If no potentially commercial
hydrocarbons are discovered, the E&E assets are written off through profit
or loss as a dry hole.
If extractable hydrocarbons are found and, subject to further appraisal
activity (e.g., the drilling of additional wells), it is probable that they
can be commercially developed, the costs continue to be carried as intangible
exploration costs, while sufficient/continued progress is made in assessing
the commerciality of the hydrocarbons
Costs directly associated with appraisal activity undertaken to determine the
size, characteristics and commercial potential of a reservoir following the
initial discovery of hydrocarbons are initially capitalized as E&E assets.
All such capitalized costs are subject to regular review, as well as review
for indicators of impairment at the end of each reporting period. This is to
confirm the continued intent to develop or otherwise extract value from the
discovery. When such intent no longer exists, or if there is a change in
circumstances signifying an adverse change in initial judgment, the costs are
written off.
When commercial reserves of hydrocarbons are determined and development is
approved by management, the relevant expenditure is transferred to oil and gas
properties. The technical feasibility and commercial viability of extracting a
mineral resource is considered to be determinable when proved or probable
reserves are determined to exist. The determination of proved or probable
reserves is dependent on reserve evaluations which are subject to significant
judgments and estimates.
Oil and gas properties
Producing assets
The Group recognizes oil and gas properties at cost less accumulated
depletion, depreciation and impairment losses. Directly attributable costs
incurred for the drilling of development wells and for the construction of
production facilities are capitalized, together with the discounted value of
estimated future costs of decommissioning obligations. Workover expenses
(costs to repair, maintain or enhance the existing well) are recognized in
profit or loss in the period in which they are incurred, unless they generates
additional reserves or prolongs the economic life of the well, in which case
they are capitalized. When components of oil and gas properties are replaced,
disposed of, or no longer in use, they are derecognized.
Once the capitalized asset restoration cost included in oil and gas properties
is reduced to nil, any residue reduction will be recognized directly in the
income statements in the period in which the change occurs as disclosed in
other income in Note 14.
Depletion and amortization expense
Depletion of oil and gas properties is calculated using the units of
production method for an asset or group of assets, from the date from which
they are available for use. The costs of those assets are depleted based on
proved and probable reserves.
Costs subject to depletion include expenditures to date, together with
approved estimated future expenditure to be incurred in developing proved and
probable reserves. Costs of major development projects are excluded from the
costs subject to depletion until they are available for use.
The impact of changes in estimated reserves is dealt with prospectively by
depleting the remaining carrying value of the asset over the remaining
expected future production. Depletion amount calculated based on production
during the year is adjusted based on the net movement of crude inventories at
year end against beginning of the year, i.e., depletion cost for crudes
produced but not lifted are capitalized as part of cost of inventories and
recognized as depletion expense when lifting occurs.
Asset restoration obligations
The Group estimates the future removal and restoration costs of oil and gas
production facilities, wells, pipelines and related assets at the time of
installation or acquisition of the assets and based on prevailing legal
requirements and industry practice.
Site restoration costs are capitalized within the cost of the associated
assets, and the provision is stated in the statement of financial position at
its total estimated present value. The estimates of future removal costs are
made considering relevant legislation and industry practice and require
management to make judgments regarding the removal date, the extent of
restoration activities required, and future removal technologies. This
estimate is evaluated on a periodic basis and any adjustment to the estimate
is applied prospectively. Changes in the estimated liability resulting from
revisions to estimated timing, amount of cash flows, or changes in the
discount rate are recognized as a change in the asset restoration liability
and related capitalized asset restoration cost within oil and gas properties.
The change in the net present value of future obligations, due to the passage
of time, is expensed as an accretion expense within financing charges. Actual
restoration obligations settled during the period reduce the decommissioning
liability.
Capitalized asset restoration costs are depleted using the units of production
method (see above accounting policy).
Plant and equipment
Plant, machinery, fixtures and fittings are stated at cost less accumulated
depreciation and accumulated impairment loss.
Depreciation is recognized so as to write off the cost or valuation of assets
(other than freehold land and properties under construction) less their
residual values over their useful lives, using the straight-line method, on
the following bases:
· Computer equipment: 3 years; and
· Fixtures and fittings: 3 years.
The estimated useful lives, residual values and depreciation method are
reviewed at each year end, with the effect of any changes in estimate
accounted for on a prospective basis.
Materials and spares which are not expected to be consumed within the next
twelve months from the year end are classified as plant and equipment.
The depreciation on the right-of-use assets is disclosed in the accounting
policy for leases.
An item of plant and equipment is derecognized upon disposal or when no future
economic benefits are expected to arise from the continued use of asset. The
gain or loss arising on the disposal or retirement of an asset is determined
as the difference between the sales proceeds and the carrying amount of the
asset and is recognized in profit or loss.
Impairment of intangible exploration and evaluation costs, oil and gas
properties, plant and equipment and right-of-use assets.
At each reporting date, the Group reviews the carrying amounts of its
intangible exploration and evaluation assets, oil and gas properties, plant
and equipment and right-of-use assets to determine whether there is any
indication that those assets have suffered an impairment loss. If such
indication exists, the recoverable amount of the asset is estimated to
determine the extent of the impairment loss (if any). Where the asset does not
generate cash flows that are independent from other assets, the Group
estimates the recoverable amount of the cash-generating unit to which the
asset belongs.
The impairment is determined on each individual cash-generating unit basis
(i.e., individual oil or gas field or individual PSC). Where there is common
infrastructure that is not possible to measure the cash flows separately for
each oil or gas field or PSC, then the impairment is determined based on the
aggregate of the relevant oil or gas fields or the combination of two or more
PSCs. When a reasonable and consistent basis of allocation can be identified,
corporate assets are also allocated to individual cash-generating units, or
otherwise they are allocated to the smallest group of cash-generating units
for which a reasonable and consistent allocation basis can be identified.
Recoverable amount is the higher of fair value less costs of disposal
("FVLCOD") and value in use ("VIU"). In assessing VIU, the estimated future
cash flows are discounted to their present value using a discount rate that
reflects current market assessments of the time value of money and the risks
specific to the asset for which estimates of future cash flows have not been
adjusted. FVLCOD will be assessed on a discounted cash flow basis where there
is no readily available market price for the asset or where there are no
recent market transactions.
If the recoverable amount of an asset (or cash-generating unit) is estimated
to be less than its carrying amount, the carrying amount of the asset (or
cash-generating unit) is reduced to its recoverable amount. An impairment loss
is recognized immediately in profit or loss, unless the relevant asset is
carried at a revalued amount, in which case the impairment loss is treated as
a revaluation decrease and to the extent that the impairment loss is greater
than the related revaluation surplus, the excess impairment loss is recognized
in profit or loss.
Where an impairment loss subsequently reverses, the carrying amount of the
asset (or cash-generating unit) is increased to the revised estimate of its
recoverable amount, but so that the increased carrying amount does not exceed
the carrying amount that would have been determined had no impairment loss
been recognized for the asset (or cash-generating unit) in prior years. A
reversal of an impairment loss is recognized immediately in profit or loss to
the extent that it eliminates the impairment loss which has been recognized
for the asset in prior years. Any increase in excess of this amount is treated
as a revaluation increase.
Inventories
Inventories are stated at the lower of cost and net realizable value. Cost is
determined as follows:
· petroleum products, comprising primarily of extracted crude oil
stored in tanks, pipeline systems and aboard vessels, and natural gas, are
valued using weighted average costing, inclusive of depletion expense; and
· materials, which include drilling and maintenance stocks, are
valued at the weighted average cost of acquisition.
Net realizable value represents the estimated selling price in the ordinary
course of business less the estimated costs of completion and the estimated
costs necessary to make the sale. The Group uses its judgement to determine
which costs are necessary to make the sale considering its specific facts and
circumstances, including the nature of the inventories. If the carrying
value exceeds net realizable value, a write-down is recognized.
Provision for slow moving materials and spares are recognized in the "other
expenses" (note 11) line item in profit or loss as they are non-trade in
nature.
Under- /Over-lift
Offtake arrangements for oil and gas produced in certain of the Group's
jointly owned operations may result in the Group lifting volumes that differ
from its entitlement share of production. The resulting imbalance between the
Group's cumulative entitlement and and volumes lifted, adjusted for inventory
movements, gives rise to underlift or overlift positions.
Revenue is recognized based on the Group's entitlement to production in the
year, rather than the volumes lifted, in accordance with the Group's
application of the entitlement method. Accordingly, no revenue is recognized
for volumes lifted in excess of entitlement or for entitled volumes not yet
lifted.
Entitlement imbalances in under/overlift positions and the movements in
inventory are included in production costs (Note 6).
An overlift position arises where the Group has lifted and sold more than its
entitlement share. This is recognized as a current liability, representing an
obligation to deliver future production to join operators. As this obligation
is settled through physical delivery of production rather than cash, it is
measured at the cost of production of the imbalance volume.
An underlift position arises where the Group has lifted less than its
entitlement share. This is recognized as a current asset, representing a right
to receive additional production in the future. Although not presented as
inventory, the underlift position is measured at the lower of cost and net
realizable value, consistent with the principles of IAS 2 Inventories, as it
is economically similar to inventory.
Non-current assets - other receivables
Other receivables classified as non-current assets comprise
decommissioning-related funds that the Group does not expect to recover within
twelve months of the reporting date. These funds arise in two distinct forms:
(i) a decommissioning trust fund held in a ring-fenced bank account for the
CWLH asset; and (ii) Production Sharing Contract ("PSC") cess funds placed
with the operator to meet the Group's share of future decommissioning
obligations under applicable PSC arrangements.
(a) CWLH Decommissioning Trust Fund
The Group has established a decommissioning trust fund for the purpose of
accumulating cash to fund the future decommissioning of the CWLH field assets.
The fund is held in a single, segregated bank account under the sole legal
ownership and operational control of an independent trustee and is governed by
the Project Plan and the Deed of Consent. Contributions made by the Group are
ring-fenced within the fund and, together with any interest earned, are
contractually restricted to meeting decommissioning expenditures. The Group
has no ability to access or independently deploy the trust funds until
decommissioning commences. The Group is obligated to make additional payments
into the fund if the asset retirement obligation exceeds the fund balance.
The Group recognizes its interest in the trust fund as a financial asset,
representing its contractual right to reimbursement of decommissioning
expenditures. This interest is separated into two components for measurement
and recognition purposes.
Reimbursement right - decommissioning obligations
The trust fund will be used to meet the Group's decommissioning liabilities, a
reimbursement right is recognized as an financial asset, measured at the
carrying amount of the corresponding decommissioning provision.
Reimbursement right - refundable component
Any excess of the Group's share of the trust fund over the carrying amount of
the recognized decommissioning provision is treated as a separate
reimbursement right. This component is recognized as an asset only where it is
probable that the surplus will be recoverable, which is typically assessed
following the completion of decommissioning activities and the settlement of
all related costs.
Both components are combined and presented as non-current other receivables in
the statement of financial position, reflecting the long-term nature of the
underlying decommissioning obligations and the expected timing of fund
utilization and recovery.
(b) PSC cess Decommissioning Funds
Nature and Structure
Under PSC arrangements in Malaysia and Indonesia, the Group and its
co-venturers are required to contribute cash to a cess fund managed by the
operator. Contributions are calculated by reference to each party's working
interest share and are held by the operator in designated accounts separate
from the operator's own funds. The amounts contributed may only be used to
fund decommissioning activities as prescribed by the relevant PSC and
applicable regulatory authority.
Key Sources of Estimation Uncertainty
The measurement of decommissioning receivables is inherently linked to the
measurement of the associated decommissioning provisions. Significant
estimation uncertainty arises in relation to:
(a) the expected timing of decommissioning activities;
(b) the total expected cost of decommissioning, which underpins the
provision and, consequently, the cap on the receivable; and
(c) the fair value of each fund, which is determined by reference to
operator-confirmed cash balances and, where applicable, any returns accruing
within the fund.
Changes in these estimates are recognized prospectively. The Group reviews the
carrying amount of each receivable at each reporting date and adjusts it to
reflect any revisions to the decommissioning provision or the fund balance.
Cash and cash equivalents
In the statement of financial position, cash and cash equivalents are of
cash (i.e. cash on hand and on-demand deposits) and cash equivalents. Cash
equivalents are short-term (generally with original maturity of three months
or less), highly liquid investments that are readily convertible to a known
amount of cash and which are subject to an insignificant risk of changes in
value. Cash equivalents are held for the purpose of meeting short-term cash
commitments rather for investment or other purposes.
Bank balances for which use by the Group is subject to third party contractual
restrictions are included as part of cash unless the restrictions result in a
bank balance no longer meeting the definition of cash. Contractual
restrictions affecting use of bank balances are disclosed in Note 29. If the
contractual restrictions to use the cash extend beyond 12 months after the end
of the reporting period, the related amounts are classified as non-current in
the statement of financial position.
For the purposes of the statement of cash flows, cash and cash equivalents
consist of cash and cash equivalents as defined above, net of outstanding bank
overdrafts which are repayable on demand and form an integral part of the
Group's cash management. Such overdrafts are presented as short-term
borrowings in the statement of financial position.
Financial instruments
Financial assets and financial liabilities are recognized in the Group's
statement of financial position when the Group becomes a party to the
contractual provisions of the instrument.
Financial assets and financial liabilities are initially measured at fair
value, except for trade receivables that do not have a significant financing
component which are measured at transaction price. Transaction costs that are
directly attributable to the acquisition or issue of the financial assets and
financial liabilities (other than financial assets and financial liabilities
at fair value through the profit and loss ("FVTPL") are added to or deducted
from the fair value of the financial assets or financial liabilities, as
appropriate, on initial recognition. Transaction costs directly attributable
to the acquisition of financial assets or financial liabilities at FVTPL are
recognized immediately in profit or loss.
Financial assets
All regular way purchases or sales of financial assets are recognized and
derecognized on a trade date basis. Regular way purchases or sales of
financial assets that require delivery of assets within the time frame
established by regulation or convention in the marketplace.
All recognized financial assets are measured subsequently in their entirety at
either amortized cost or fair value, depending on the classification of the
financial assets.
Classification of financial assets
Debt instruments that meet the following conditions are measured subsequently
at amortized cost:
· the financial asset is held within a business model whose
objective is to hold financial assets in order to collect contractual cash
flows; and
· the contractual terms of the financial asset give rise on
specified dates to cash flows that are solely payments of principal and
interest on the principal amount outstanding.
Debt instruments that meet the following conditions are subsequently measured
at fair value through other comprehensive income ("FVTOCI"):
· the financial asset is held within a business model whose
objective is achieved by both collecting contractual cash flows and selling
the financial assets; and
· the contractual terms of the financial asset give rise on
specified dates to cash flows that are solely payments of principal and
interest on the principal amount outstanding.
By default, all other financial assets are subsequently measured at FVTPL.
Despite the foregoing, the Group may make the following irrevocable election /
designation at initial recognition of a financial asset:
· the Group may irrevocably elect to present subsequent changes in
fair value of an equity investment in other comprehensive income if certain
criteria are met (see (iii) below); and
the Group may irrevocably designate a debt investment that meets the amortized
cost or FVTOCI criteria as measured at FVTPL if doing so eliminates or
significantly reduces an accounting mismatch (see (iv) below).
(i) Amortized cost and effective interest method
The effective interest method is a method of calculating the amortized cost of
a debt instrument and of allocating interest income over the relevant period.
For financial assets other than purchased or originated credit-impaired
financial assets (i.e. assets that are credit-impaired on initial
recognition), the effective interest rate is the rate that exactly discounts
estimated future cash receipts (including all fees and points paid or received
that form an integral part of the effective interest rate, transaction costs
and other premiums or discounts) excluding expected credit losses, through the
expected life of the debt instrument on initial recognition, or, where
appropriate, a shorter period, to the gross carrying amount of the debt
instrument on initial recognition.
The amortized cost of a financial asset is the amount at which the financial
asset is measured at initial recognition minus the principal repayments, plus
the cumulative amortization using the effective interest method of any
difference between that initial amount and the maturity amount, adjusted for
any loss allowance. The gross carrying amount of a financial asset is the
amortized cost of a financial asset before adjusting for any loss allowance.
Interest income is recognized using the effective interest method for debt
instrument measured subsequently at amortized cost and at FVTOCI. For
financial assets other than purchased or originated credit impaired financial
assets, interest income is calculated by applying the effective interest rate
to the gross carrying amount of a financial asset, except for financial assets
that have subsequently become credit impaired. For financial assets that have
subsequently become credit impaired, interest income is recognized by applying
the effective interest rate to the amortized cost of the financial asset,
except for financial assets that have subsequently become credit-impaired (see
below). For financial assets that have subsequently become credit-impaired,
interest income is recognized by applying the effective interest rate to the
amortized cost of the financial asset. If, in subsequent reporting periods,
the credit risk on the credit impaired financial instrument improves so that
the financial asset is no longer credit impaired, interest income is
recognized by applying the effective interest rate to the gross carrying
amount of the financial asset.
For purchased or originated credit-impaired financial assets, the Group
recognizes interest income by applying the credit-adjusted effective interest
rate to the amortized cost of the financial asset from initial recognition.
The calculation does not revert to the gross basis even if the credit risk of
the financial asset subsequently improves so that the financial asset is no
longer credit-impaired.
Interest income is recognized in profit or loss and is included in "other
income" line item (Note 14).
Impairment of financial assets
The Group recognizes a loss allowance for expected credit losses on
investments in debt instruments that are measured at amortized cost or at
FVTOCI, lease receivables, trade receivables and contract assets, as well as
on financial guarantee contracts. The amount of expected credit losses is
updated at each reporting date to reflect changes in credit risk since initial
recognition of the respective financial instrument.
The concentration of credit risk 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 and a different single customer for gas in Indonesia. All
customers have an A2 credit rating (Moody's). All trade receivables are
generally settled 30 days after the sale date. In the event that an invoice is
issued on a provisional basis then the final reconciliation is paid within
three days of the issuance of the final invoice, largely mitigating any credit
risk.
The Group always recognizes lifetime expected credit losses (ECL) for trade
receivables, contract assets and lease receivables. The expected credit losses
on these financial assets are estimated using a provision matrix based on the
Group's historical credit loss experience, adjusted for factors that are
specific to the debtors, general economic conditions and an assessment of both
the current as well as the forecast direction of conditions at the reporting
date, including time value of money where appropriate.
For all other financial instruments, the Group recognizes lifetime ECL when
there has been a significant increase in credit risk since initial
recognition. However, if the credit risk on the financial instrument has not
increased significantly since initial recognition, the Group measures the loss
allowance for that financial instrument at an amount equal to 12-month ECL.
Lifetime ECL represents the expected credit losses that will result from all
possible default events over the expected life of a financial instrument. In
contrast, 12-month ECL represents the portion of lifetime ECL that is expected
to result from default events on a financial instrument that are possible
within 12 months after the reporting date.
(i) Significant increase in credit risk
In assessing whether the credit risk on a financial instrument has increased
significantly since initial recognition, the Group compares the risk of a
default occurring on the financial instrument at the reporting date with the
risk of a default occurring on the financial instrument as at the date of
initial recognition. In making this assessment, the Group considers both
quantitative and qualitative information that is reasonable and supportable,
including historical experience and forward-looking information that is
available without undue cost or effort. Forward-looking information considered
includes the future prospects of the industries in which the Group's debtors
operate, obtained from economic expert reports, financial analysts,
governmental bodies, relevant think-tanks and other similar organizations, as
well as consideration of various external sources of actual and forecast
economic information that relate to the Group's core operations.
In particular, the following information is taken into account when assessing
whether credit risk has increased significantly since initial recognition:
· an actual or expected significant deterioration in the financial
instrument's external (if available) or internal credit rating;
· significant deterioration in external market indicators of credit risk for
a particular financial instrument, e.g. a significant increase in the credit
spread, the credit default swap prices for the debtor, or the length of time
or the extent to which the fair value of a financial asset has been less than
its amortized cost;
· existing or forecast adverse changes in business, financial or
economic conditions that are expected to cause a significant decrease in the
debtor's ability to meet its debt obligations;
· an actual or expected significant deterioration in the operating
results of the debtor;
· significant increases in credit risk on other financial
instruments of the same debtor; and
· an actual or expected significant adverse change in the
regulatory, economic, or technological environment of the debtor that results
in a significant decrease in the debtor's ability to meet its debt
obligations.
Irrespective of the outcome of the above assessment, the Group presumes that
the credit risk on a financial asset has increased significantly since initial
recognition when contractual payments are more than 30 days past due, unless
the Group has reasonable and supportable information that demonstrates
otherwise.
Despite the foregoing, the Group assumes that the credit risk on a financial
instrument has not increased significantly since initial recognition if the
financial instrument is determined to have lo credit risk at the reporting
date. A financial instrument is determined to have low credit risk if:
· the financial instrument has a low risk of default;
· the debtor has a strong capacity to meet its contractual cash
flow obligations in the near term; and
· adverse changes in economic and business conditions in the longer
term may, but will not necessarily, reduce the ability of the borrower to
fulfil its contractual cash flow obligations.
The Group regularly monitors the effectiveness of the criteria used to
identify whether there has been a significant increase in credit risk and
revises them as appropriate to ensure that the criteria are capable of
identifying a significant increase in credit risk before the amount becomes
past due.
(ii) Definition of default
The Group considers the following as constituting an event of default for
internal credit risk management purposes as historical experience indicates
that financial assets that meet either of the following criteria are generally
not recoverable:
· when there is a breach of financial covenants by the
counterparty; or
· information developed internally or obtained from external
sources indicates that the debtor is unlikely to pay its creditors, including
the Group, in full (without taking into account any collateral held by the
Group).
Irrespective of the above analysis, the Group considers that default has
occurred when a financial asset is more than 90 days past due unless the Group
has reasonable and supportable information to demonstrate that a more lagging
default criterion is more appropriate.
(iii) Credit-impaired financial assets
A financial asset is credit-impaired when one or more events that have a
detrimental impact on the estimated future cash flows of that financial asset
have occurred. Evidence that a financial asset is credit-impaired includes
observable data about the following events:
· significant financial difficulty of the issuer of the borrower;
· a breach of contract, such as a default or past due event (see (ii) above);
· the lender(s) of the borrower, for economic or contractual
reasons relating to the borrower's financial difficulty, having granted to the
borrower a concession(s) that the lender(s) would not otherwise consider;
· it is becoming probable that the borrower will enter bankruptcy
or other financial reorganization; or
· the disappearance of an active market for that financial asset
because of financial difficulties
(iv) Write-off policy
The Group writes off a financial asset when there is information indicating
that the debtor is in severe financial difficulty and there is no realistic
prospect of recovery, e.g. when the debtor has been placed under liquidation
or has entered into bankruptcy proceedings, or in the case of trade
receivables, when the amounts are over two years past due, whichever occurs
sooner. Financial assets written off may still be subject to enforcement
activities under the Group's recovery procedures, taking into account legal
advice where appropriate. Any recoveries made are recognized in profit or
loss.
(v) Measurement and recognition of expected credit losses
The measurement of ECL is a function of the probability of default, loss given
default (i.e., the magnitude of the loss if there is a default), and the
exposure at default. The assessment of the probability of default and loss
given default is based on historical data adjusted by forward-looking
information as described above. As for the exposure at default, for financial
assets, this is represented by the assets' gross carrying amount at the
reporting date; for financial guarantee contracts, the exposure includes the
amount of guaranteed debt that has been drawn down as at the reporting date,
together with any additional guaranteed amounts expected to be drawn down by
the borrower in the future by default date determined based on historical
trend, the Group's understanding of the specific future financing needs of the
debtors, and other relevant forward-looking information.
For financial assets, the expected credit loss is estimated as the difference
between all contractual cash flows that are due to the Group in accordance
with the contract and all the cash flows that the Group expects to receive,
discounted at the original effective interest rate. For a lease receivable,
the cash flows used for determining the expected credit losses is consistent
with the cash flows used in measuring the lease receivable in accordance with
IFRS 16.
If the Group has measured the loss allowance for a financial instrument at an
amount equal to lifetime ECL in the previous reporting period, but determines
at the current reporting date that the conditions for lifetime ECL are no
longer met, the Group measures the loss allowance at an amount equal to
12-month ECL at the current reporting date, except for assets for which the
simplified approach was used.
The Group recognizes an impairment gain or loss in profit or loss for all
financial instruments with a corresponding adjustment to their carrying amount
through a loss allowance account, except for investments in debt instruments
that are measured at FVTOCI, for which the loss allowance is recognized in
other comprehensive income and accumulated in the investment revaluation
reserve, and does not reduce the carrying amount of the financial asset in the
statement of financial position.
Derecognition of financial assets
The Group derecognizes a financial asset only when the contractual rights to
the cash flows from the asset expire, or when it transfers the financial asset
and substantially all the risks and rewards of ownership of the asset to
another entity. If the Group neither transfers nor retains substantially all
the risks and rewards of ownership and continues to control the transferred
asset, the Group recognizes its retained interest in the asset and an
associated liability for amounts it may have to pay. If the Group retains
substantially all the risks and rewards of ownership of a transferred
financial asset, the Group continues to recognize the financial asset and also
recognizes a collateralized borrowing for the proceeds received.
On derecognition of a financial asset measured at amortized cost, the
difference between the asset's carrying amount and the sum of the
consideration received and receivable is recognized in profit or loss. In
addition, on derecognition of an investment in a debt instrument classified as
at FVTOCI, the cumulative gain or loss previously accumulated in the
investments revaluation reserve is reclassified to profit or loss. In
contrast, on derecognition of an investment in an equity instrument which the
Group has elected on initial recognition to measure at FVTOCI, the cumulative
gain or loss previously accumulated in the investments revaluation reserve is
not reclassified to profit or loss, but is transferred to retained earnings.
Financial liabilities and equity
Classification as debt or equity
Debt and equity instruments are classified as either financial liabilities or
as equity in accordance with the substance of the contractual arrangements and
the definitions of a financial liability and an equity instrument
Equity instruments
An equity instrument is any contract that evidences a residual interest in the
assets of an entity after deducting all of its liabilities. Equity instruments
issued by the Group are recognized at the proceeds received, net of direct
issue costs.
The repurchase of equity instruments issued by the Group is recognized and
deducted directly in equity. No gain or loss is recognized in profit or loss
on the purchase, sale, issue or cancellation of equity instruments issued by
the Group.
Financial liabilities
All financial liabilities are measured subsequently at amortized cost using
the effective interest method or at FVTPL.
However, financial liabilities that arise when a transfer of a financial asset
does not qualify for derecognition or when the continuing involvement approach
applies, and financial guarantee contracts issued by the Group, are measured
in accordance with the specific accounting policies set out below.
Financial liabilities at FVTPL
Financial liabilities are classified as at FVTPL when the financial liability
is (i) contingent consideration of an acquirer in a business combination, (ii)
held for trading or (iii) it is designated as at FVTPL.
A financial liability is classified as held for trading if either:
· it has been acquired principally for the purpose of repurchasing
it in the near term; or
· on initial recognition it is part of a portfolio of identified
financial instruments that the Group manages together and has a recent actual
pattern of short-term profit-taking; or
· it is a derivative, except for a derivative that is a financial
guarantee contract or a designated and effective hedging instrument.
A financial liability other than a financial liability held for trading or
contingent consideration of an acquirer in a business combination may be
designated as at FVTPL upon initial recognition if either:
· such designation eliminates or significantly reduces a measurement or
recognition inconsistency that would otherwise arise; or
· the financial liability forms part of a group of financial assets or
financial liabilities or both, which is managed and its performance is
evaluated on a fair value basis, in accordance with the Group's documented
risk management or investment strategy, and information about the grouping is
provided internally on that basis; or
· it forms part of a contract containing one or more embedded
derivatives, and IFRS 9 permits the entire combined contract to be designated
as at FVTPL.
Financial liabilities at FVTPL are measured at fair value, with any gains or
losses arising on changes in fair value recognized in profit or loss to the
extent that they are not part of a designated hedging relationship (see Hedge
accounting policy). The net gain or loss recognized in profit or loss
incorporates any interest paid on the financial liability and is included in
either "other financial gains" (Note 16) or "finance costs" (Note 15) line
item in profit or loss.
Financial liabilities measured subsequently at amortized cost
Financial liabilities, that are not (i) contingent consideration of an
acquirer in a business combination, (ii) held-for-trading, or (iii) designated
as at FVTPL, are measured subsequently at amortized cost using the effective
interest method.
The effective interest method is a method of calculating the amortized cost of
a financial liability and of allocating interest expense over the relevant
period. The effective interest rate is the rate that exactly discounts
estimated future cash payments (including all fees paid and points or received
that form an integral part of the effective interest rate, transaction costs
and other premiums or discounts) through the expected life of the financial
liability, or (where appropriate) a shorter period, to the amortized cost of a
financial liability.
Derecognition of financial liabilities
The Group derecognizes financial liabilities when, and only when, the Group's
obligations are discharged, cancelled or they expire. The difference between
the carrying amount of the financial liability derecognized and the
consideration paid and payable is recognized in profit or loss.
When the Group exchanges with the existing lender one debt instrument into
another one with substantially different terms, such exchange is accounted for
as an extinguishment of the original financial liability and the recognition
of a new financial liability. Similarly, the Group accounts for substantial
modification of terms of an existing liability or part of it as an
extinguishment of the original financial liability and the recognition of a
new liability. It is assumed that the terms are substantially different if the
discounted present value of the cashflows under the new terms, including any
fees paid net of any fees received and discounted using the original effective
interest rate is at least 10 per cent different from the discounted present
value of the remaining cashflows of the original financial liability. If the
modification is not substantial, the difference between: (1) the carrying
amount of the liability before the modification; and (2) the present value of
the cash flows after modification is recognized in profit or loss as the
modification gain or loss within other gains and losses.
Derivative financial instruments
The Group enters into a variety of derivative financial instruments to manage
its exposure to commodity price, interest rate and foreign exchange risks.
Derivatives are initially recognized at fair value at the date a derivative
contract is entered into and subsequently remeasured to their fair value at
each reporting date. The resulting gain or loss is recognized in profit or
loss immediately unless the derivative is designated and effective as a
hedging instrument, in which event the timing of the recognition in profit or
loss depends on the nature of the hedge relationship.
A derivative with a positive fair value is recognized as a financial asset
whereas a derivative with a negative fair value is recognized as a financial
liability. Derivatives are not offset in the financial statements unless the
Group has both a legally enforceable right and intention to offset. The impact
of the master netting agreements on the Group's financial position is
disclosed in Note 41. A derivative is presented as a non-current asset or a
non-current liability if the remaining maturity of the instrument is more than
12 months and it is not due to be realized or settled within 12 months. Other
derivatives are presented as current assets or current liabilities.
Hedge accounting
All hedges are classified as cash flow hedges, which hedges exposure to the
variability in cash flows that is either attributable to a particular risk
associated with a recognized asset or liability, or a component of a
recognized asset or liability, or a highly probable forecasted transaction.
At the inception of the hedge relationship, the Group documents the
relationship between the hedging instrument and the hedged item, along with
its risk management objectives and its strategy for undertaking various hedge
transactions. Furthermore, at the inception of the hedge and on an ongoing
basis, the Group documents whether the hedging instrument is highly effective
in offsetting changes in fair values or cash flows of the hedged item
attributable to the hedged risk, which is when the hedging relationships meet
all of the following hedge effectiveness requirements:
· there is an economic relationship between the hedged item and the
hedging instrument;
· the effect of credit risk does not dominate the value changes
that result from that economic relationship; and
· the hedge ratio of the hedging relationship is the same as that
resulting from the quantity of the hedged item that the Group actually hedges
and the quantity of the hedging instrument that the Group actually uses to
hedge that quantity of hedged item.
If a hedging relationship ceases to meet the hedge effectiveness requirement
relating to the hedge ratio but the risk management objective for that
designated hedging relationship remains the same, the Group adjusts the hedge
ratio of the hedging relationship (i.e. rebalances the hedge) so that it meets
the qualifying criteria again.
The Group designates the full change in the fair value of a forward contract
(i.e. including the forward elements) as the hedging instrument, for all of
its hedging relationships involving forward contracts.
The Group designates only the intrinsic value of option contracts as a hedged
item, i.e. excluding the time value of the option. The changes in the fair
value of the aligned time value of the option are recognized in other
comprehensive income and accumulated in the cost of hedging reserve. If the
hedged item is transaction-related, the time value is reclassified to profit
or loss when the hedged item affects profit or loss. If the hedged item is
time-period related, then the amount accumulated in the cost of hedging
reserve is reclassified to profit or loss on a rational basis - the Group
applies straight-line amortization. Those reclassified amounts are recognized
in profit or loss in the same line as the hedged item. If the hedged item is a
non-financial item, then the amount accumulated in the cost of hedging reserve
is removed directly from equity and included in the initial carrying amount of
the recognized non-financial item. Furthermore, if the Group expects that some
or all of the loss accumulated in cost of hedging reserve will not be
recovered in the future, that amount is immediately reclassified to profit or
loss.
Note 41 sets out details of the fair values of the derivative instruments used
for hedging purposes.
Movements in the hedging reserve in equity are detailed in Note 35.
Fair value hedges
The fair value change on qualifying hedging instruments is recognized in
profit or loss except when the hedging instrument hedges an equity instrument
designated at FVTOCI in which case it is recognized in other comprehensive
income.
The carrying amount of a hedged item not already measured at fair value is
adjusted for the fair value change attributable to the hedged risk with a
corresponding entry in profit or loss. For debt instruments measured at
FVTOCI, the carrying amount is not adjusted as it is already at fair value,
but the gain or loss on the hedging instrument is recognized in profit or loss
instead of other comprehensive income. When the hedged item is an equity
instrument designated at FVTOCI, the gain or loss on the hedging instrument
remains in other comprehensive income to match that of the hedging instrument.
Where gains or losses on hedging instruments are recognized in profit or loss,
they are recognized in the same line as those on the hedged item.
The Group discontinues hedge accounting only when the hedging relationship (or
a part thereof) ceases to meet the qualifying criteria (after rebalancing, if
applicable). This includes instances when the hedging instrument expires or is
sold, terminated or exercised. The discontinuation is accounted for
prospectively. The fair value adjustment to the carrying amount of the hedged
item arising from the hedged risk is amortized to profit or loss from that
date.
Cash flow hedges
The effective portion of changes in the fair value of derivatives and other
qualifying hedging instruments that are designated and qualify as cash flow
hedges is recognized in other comprehensive income and accumulated under the
heading of cash flow hedging reserve, limited to the cumulative change in fair
value of the hedged item from inception of the hedge. The gain or loss
relating to the ineffective portion is recognized immediately in profit or
loss in either "other financial gains" (Note 16) or "finance costs" (Note 15)
line item.
Amounts previously recognized in other comprehensive income and accumulated in
equity are reclassified to profit or loss in the periods when the hedged item
affects profit or loss, in the same line as the recognized hedged item.
However, when the hedged forecast transaction results in the recognition of a
non-financial asset or a non-financial liability, the gains and losses
previously recognized in other comprehensive income and accumulated in equity
are removed from equity and included in the initial measurement of the cost of
then on-financial asset or non-financial liability. This transfer does not
affect other comprehensive income.
Furthermore, if the Group expects that some or all of the loss accumulated in
the cash flow hedging reserve will not be recovered in the future, that amount
is immediately reclassified to profit or loss.
The Group discontinues hedge accounting only when the hedging relationship (or
a part thereof) ceases to meet the qualifying criteria (after rebalancing, if
applicable). This includes instances when the hedging instrument expires or is
sold, terminated or exercised. The discontinuation is accounted for
prospectively. Any gain or loss recognized in other comprehensive income and
accumulated in cash flow hedge reserve at that time remains in equity and is
reclassified to profit or loss when the forecast transaction occurs. When a
forecast transaction is no longer expected to occur, the gain or loss
accumulated in the cash flow hedge reserve is reclassified immediately to
profit or loss.
Fair value estimation of financial assets and financial liabilities
The fair value of current financial assets and financial liabilities carried
at amortized cost, approximate their carrying amounts, as the effect of
discounting is immaterial.
Provisions
Provisions are recognized when the Group has a present obligation (legal or
constructive) as a result of a past event, it is probable that the Group will
be required to settle that obligation and a reliable estimate can be made of
the amount of the obligation.
The amount recognized as a provision is the best estimate of the consideration
required to settle the present obligation at the reporting date, taking into
account the risks and uncertainties surrounding the obligation. Where a
provision is measured using the cash flows estimated to settle the present
obligation, its carrying amount is the present value of those cash flows
(where the effect of the time value of money is material).
The provisions held by the Group are asset restoration obligations, contingent
payments, employee benefits and incentive scheme, as set out in Note 36.
When some or all of the economic benefits required to settle a provision are
expected to be recovered from a third party, a receivable is recognized as an
asset if it is virtually certain that reimbursement will be received and the
amount of the receivable can be measured reliably.
Share-based payments
Share-based incentive arrangements are provided to employees, allowing them to
acquire shares of the Group. The fair value of equity-settled options granted
is recognized as an employee expense, with a corresponding increase in equity.
Equity-settled share options are valued at the date of grant using the
Black-Scholes pricing model, and are charged to operating costs over the
vesting period of the award. The charge is modified to take account of options
granted to employees who leave the Group during the vesting period and forfeit
their rights to the share options. The fair value determined at the grant date
of the equity-settled share-based payments is expensed on a straight-line
basis over the vesting period, based on the Group's estimate of the number of
equity instruments that will eventually vest. At each reporting date, the
Group revises its estimate of the number of equity instruments expected to
vest as a result of the effect of non-market-based vesting conditions. The
impact of the revision of the original estimates, if any, is recognized in
profit or loss such that the cumulative expense reflects the revised estimate,
with a corresponding adjustment to reserves.
Equity-settled share-based payment transactions with parties other than
employees are measured at the fair value of goods or services received, except
where that fair value cannot be estimated reliably, in which case they are
measured at the fair value of the equity instruments granted, measured at the
date at which the entity obtains the goods or the counterparty renders the
service.
For cash-settled share-based payments, a liability is recognized for the goods
or services acquired, measured initially at the fair value of the liability.
At each reporting date until the liability is settled, and at the date of
settlement, the fair value of the liability is remeasured, with any changes in
fair value recognized in profit or loss for the year.
4. Critical accounting judgements and key sources of estimation uncertainty
In applying the Group's accounting policies, which are described in Note 3,
the Directors are required to make judgements (other than those involving
estimations) that have a significant impact on the amounts recognized and to
make 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.
Critical judgements in applying the Group's accounting policies
The following are the critical judgements, apart from those involving
estimations (which are presented separately below), that the Directors have
made in the process of applying the Group's accounting policies and that have
the most significant effect on the amounts recognized in financial statements.
a) Impairment of oil and gas properties
The Group assesses each asset or cash-generating unit ('CGU') (excluding
goodwill, which is assessed annually regardless of indicators) at the end of
year to determine whether any indication of impairment exists. Assessment of
indicators of impairment or impairment reversal and the determination of the
appropriate grouping of assets into a CGU or the appropriate grouping of CGUs
for impairment purposes require significant judgement.
The Group's judgement is that oil and gas producing assets are generally
assessed licence level CGUs, reflecting the lowest level at which cash inflows
are largely independent and separately monitored for internal management
purposes. Accordingly, producing assets such as Montara, CWLH and Stag are
assessed as individual CGUs.
Exploration and non-producing assets are assessed at licence level CGUs, based
on the geological and operational characteristics of each licence and the
manner in which expenditure decisions and potential future development
activities are managed.
This judgement is based on the Group's internal reporting structure,
operational decision-making processes, and the way asset performance and cash
flows are monitored. The resulting CGU groupings applied in impairment testing
are set out in Note 13.
During the year, the Group recognized impairment charges of US$126.0 million,
primarily arising from changes in forward commodity price assumptions, updated
production profiles, and revised cost assumptions impacting the recoverable
amounts of certain oil and gas CGUs.
b) Impairment of intangible exploration assets
The Group takes into consideration the technical feasibility and commercial
viability of extracting a mineral resource and whether there is any adverse
information that will affect the final investment decision. Additionally, the
Group performed recoverability assessment for the expenditures incurred based
on their cost recoverability in accordance with the terms of the relevant
production sharing contracts.
Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of estimation
uncertainty at the reporting period that may have a significant risk of
causing a material adjustment to the carrying amounts of assets and
liabilities within the next financial year, are discussed below.
a) Reserves estimates
The Group's estimated reserves are management assessments, and are
independently assessed by an independent third party, which involves reviewing
various assumptions, interpretations and assessments. These include
assumptions regarding commodity prices, exchange rates, future production,
transportation costs, climate related risks and interpretations of geological
and geophysical models to make assessments of the quality of reservoirs and
the anticipated recoveries. Changes in reported reserves can impact asset
carrying amounts, the provision for restoration and the recognition of
deferred tax assets, due to changes in expected future cash flows. Reserves
are integral to the amount of depreciation, depletion and amortization charged
to the statement of profit or loss and other comprehensive income, and the
calculation of inventory. Based on the analysis performed, a 10% decrease in
the reserves estimates would result in an increase in impairment charge of
US$65.4 million and a 10% increase in the reserves estimates would result in
an decrease in impairment of US$54.0 million. The Directors consider 10%
movements to the existing reserves a reasonable assumption based on the
historical technical adjustments during the annual reserves assessment
performed by an independent third party and also in view of the mature assets
that the Group owns with long production history and therefore less volatility
in reserves estimates is anticipated.
b) Impairment of oil and gas properties and intangible exploration
assets
For the impairment assessment of oil and gas properties and intangible
exploration assets, the Directors assess the recoverable amounts using the VIU
approach. The estimated future cash flows are prepared based on estimated 2p
reserves (excluding contingent reserve), future production profiles, future
hydrocarbon price assumptions and costs. The future hydrocarbon price
assumptions used are highly judgemental and may be subject to increased
uncertainty given climate change and the global energy transition. The
estimated future cash flows also included the carbon costs estimates of each
asset, where applicable. The inclusion of carbon cost estimates of each asset
is based on the Directors' best estimate of any expected applicable carbon
emission costs payable. This requires Directors' best estimate of how future
changes to relevant carbon emission cost policies and/or legislation are
likely to affect the future cash flows of the Group's applicable CGUs, whether
enacted or not. Future potential carbon cost estimates of each asset were
included to the extent the Directors have sufficient information to make such
estimates.
The Directors further take into consideration the impact of climate change on
estimated future commodity prices with the application of price assumptions
based on economic modelling in scenarios in which the goals of the COP 21
Paris agreement are reached ("Paris aligned price assumptions", see below).
The carrying amounts of intangible exploration assets, oil and gas properties
and right-of-use assets are disclosed in Notes 20, 21 and 22, respectively.
The Group recognizes that climate change and the energy transition is likely
to impact the demand for oil and gas, thus affecting the future prices of
these commodities and the timing of decommissioning activities. This in turn
may affect the recoverable amount of the Group's oil and gas properties and
intangible exploration assets, and the carrying amount of the ARO provision.
The Group acknowledges that there is a range of possible energy transition
scenarios that may indicate different outcomes for oil prices. There are
inherent limitations with scenario analysis and it is difficult to predict
which, if any, of the scenarios might eventuate.
The Group has assessed the potential impacts of climate change and the
transition to a lower carbon economy in preparing the consolidated financial
statements, including the Group's current assumptions relating to demand for
oil and gas and their impact on the Group's long-term price assumptions, and
also taking into consideration the forecasted long-term prices and demand for
oil and gas under the Paris aligned scenarios (IEA's NZE by 2050, as per WEO
2025). The Group's current oil price assumption for internal planning purposes
is broadly in line with the IEA's Current Policy Scenarios ("CPS"), which in
turn is underpinned by climate policies and targets already in place. The
Group has assessed the potential impacts of climate change and the transition
to a lower carbon economy in preparing the consolidated financial statements.
This is achieved by running the IEA's NZE scenario through the Group's
financial models and assessing the impact on profitability, cash flow and
asset values. The IEA's NZE by 2050 case assumes global oil demand to fall
from 79 mb/d in 2024 to 54 mb/d by 2035 and 19 mb/d by 2050. Prices fall to
US$62.0/bbl in 2030 and trend lower thereafter. The oil price differential
between CPS and NZE becomes significant from 2030 onwards. The Group monitors
energy transition risks and, through its annual risk reviews, challenges its
base case assumptions on a regular basis.
The Directors will continue to review various global and regional energy
transition developments and their impacts on price assumptions, including
Paris aligned scenario price assumptions and demand in line with the scenarios
based on decrease to emissions as the energy transition progresses and will
continue to take these into consideration in the future impairment
assessments.
Sensitivity analysis
The Directors assess the impact of a change in cash flows in impairment
testing arising from a 10% reduction in price assumptions used at year end,
sourced from independent third party, ERCEs and approved by the Directors. The
analysis relates solely to oil and gas properties, as no impairment indicators
or sensitivity testing are identified for intangible exploration and
evaluation assets.
The forecasted price assumptions are US$62.0/bbl in 2026, US$67.0/bbl in 2027,
US$72.0/bbl in 2028, US$73.4/bbl in 2029 and an average of US$82.9/bbl between
2030 to 2040. The Directors are of the view that these price assumptions are
aligned with the Group's internal forecasts at the year-end, reflecting
long-term views of global supply and demand. The price assumptions used are
reviewed and approved by the Directors. Based on the analysis performed, the
Directors concluded that a 10% price reduction in isolation under the various
scenarios would result in an increase in impairment charge of US$73.7 million
and a 10% price increase in isolation would decrease the current impairment
charge by US$55.5 million.
Since the beginning of 2026, Dated Brent has averaged US$88/bbl, trading
within a range of US$61-US$144/bbl. While prices have been volatile, primarily
due to Middle East tensions there has been a corresponding increase in
longer‑term price expectations. The forecast rates are US$87/bbl in 2026,
US$80/bbl in 2027, US$75/bbl in 2028, US$77/bbl in 2029 and an average of
US$83/bbl from 2030 onwards.
Applying the ERCE March 2026 price assumptions to the 2025 impairment model
results in a combined pre‑tax impairment of US$44.7 million, comprising
US$29.9 million for Stag and US$14.7 million for Montara. This represents a
65% reduction compared to the US$126.0 million as at 31 December 2025.
The oil price sensitivity analyses above do not, however, represent the
Directors' best estimate of any impairments that might be recognized as they
do not fully incorporate consequential changes that may arise, such as
reductions in costs and changes to business plans, phasing of development,
levels of reserves and resources, and production volumes. As an example, as
prices fall, upstream operating costs typically decrease as companies cut
expenses and renegotiate contracts. Lower activity reduces demand for
logistics, engineering, and project management services, leading to lower
costs. Construction and labor costs also drop as spending slows, pushing down
contractor rates and wages. Together, these factors drive an overall reduction
in industry operating costs. The oil price sensitivity analysis therefore
does not reflect a linear relationship between price and value that can be
extrapolated.
The Directors also tested the impact of a 10% change to the discount rate used
of 10.0% (2024: 11.1%) in Australia (Stag, Montara & CWLH), 11.6% (2024:
12.8%) in Malaysia (PenMal) and 12.6% (2024: 14.0%) in Indonesia (Akatara),
for impairment testing of oil and gas properties, and concluded that a 10%
increase in the discount rate would result in an increase in impairment charge
of US$5.2 million and a 10% decrease in the discount rate would decrease the
impairment charge by US$5.4 million.
The Directors assessed the impact of the change in cash flows used in
impairment testing arising from the application of the oil price assumptions
under the Net Zero Emissions by 2050 Scenario plus the inclusion of carbon
cost estimates as disclosed above. The oil prices in US$ under the Net Zero
Emissions by 2050 Scenario assumed for each asset are as follows:
2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
Brent 63.2 64.1 70.3 66.1 62.0 57.8 53.6 49.4 45.2 41.0
Based on the analysis performed, the reduction in operating cash flows under
the Net Zero Emissions by 2050 Scenario would result to in a impairment charge
of US$165.3 million to the Group's oil and gas properties. The assumptions
under the Net Zero Emissions by 2050 Scenario do not reflect the existing
market conditions and are dependent on various factors in the future covering
supply, demand, economic and geopolitical events and therefore are inherently
uncertain and subject to significant volatility and hence unlikely to reflect
the future outcome.
c) Asset restoration obligations
The Group estimates the future removal and restoration costs of oil and gas
production facilities, wells, pipelines and related assets at the time of
installation of the assets and reviewed subsequently at the end of each
reporting period. In most instances the removal of these assets will occur
many years in the future.
The estimate of future removal costs is made considering relevant legislation
and industry practice and requires the Directors to make judgments regarding
the removal date, the extent of restoration activities required and future
costs and removal technologies.
The carrying amounts of the Group's ARO is disclosed in Note 36 to the
financial statements.
Sensitivity analysis
The following sensitivities have been performed on the key assumptions used in
estimating the decommissioning liability. The Directors consider a 1% point
movement in the discount rate and inflation rate, a 10% movement in current
estimated costs and a one year movement in the estimated decommissioning year
to represent reasonably possible changes based on historical adjustments to
the risk-free rates, base decommissioning costs and estimated decommissioning
timing.
The results of the sensitivity analysis are set out in the table below.
Assumption Change in assumption Increase/(decrease) in provision (US$'000)
Discount rate Increase by 1% (49,121)
Decrease by 1% 54,636
Inflation rate Increase by 1% 55,093
Decrease by 1% (50,412)
Current estimate costs Increase by 10% 52,975
Decrease by 10% (52,975)
Estimated decommissioning year One year acceleration
8,841
One year deferral (10,323)
d) Deferred tax assets
Deferred tax assets are recognized for all unutilized tax losses, unabsorbed
capital allowances and unabsorbed reinvestment allowances to the extent that
it is probable that taxable profit will be available against which it can be
utilized. Significant management judgement is required to determine the amount
of deferred tax assets that can be recognized, based on the likely timing and
level of future taxable profits together with future tax planning strategies.
If the Group had recognized the deferred tax assets arising during the current
year that remain unrecognized at the reporting date, profit for the year would
have increased by US$14.8 million. The amount of recognized deferred tax
assets is disclosed in Note 26.
5. Revenue
The Group presently derives its revenue from contracts with customers for the
sale of hydrocarbon products including crude oil, gas, condensate and LPG.
In line with the revenue accounting policies set out in Note 3, all revenue is
recognized at a point in time.
2025 2024
US$'000 US$'000
Liquids revenue 314,897 405,964
Hedging gain/(loss) (Note 35 and Note 41) 2,220 (27,417)
317,117 378,547
Gas revenue 41,126 7,962
LPG revenue 34,444 4,313
Condensate revenue 15,373 4,214
408,060 395,036
As required under the RBL facility as disclosed in Note 37, the Group entered
into commodity swap contracts to hedge approximately 20% to 70% of its
forecasted planned liquids production. The Group applies hedge accounting to
these commodity swap contracts. See Note 41 for details of the commodity swap
contracts.
6. Production costs
2025 2024
US$'000 US$'000
Operating costs 134,209 144,701 40 (#_ftn40)
Workovers 11,200 20,797
Logistics 33,429 26,928
Other repairs and maintenance 47,708 64,620 41 (#_ftn41)
Tariffs and transportation costs 6,190 8,451
Inventories written down 6,755 -
Underlift and overlift and crude inventories movement (6,831) 21,411
232,660 286,908
Operating costs predominately consist of offshore manpower costs of US$30.6
million (2024: US$28.8 million), technical onshore office based costs of
US$13.6 million (2024: US$11.6 million), other production related costs for a
total of US$27.6 million (2024: US$45.6 million), supplementary payment of
US$3.1 million (2024: US$6.8 million), royalties of US$11.9 million (2024:
US$3.4 million), insurance of US$5.3 million (2024: US$5.3 million) and
non-operated assets production costs of US$34.6 million (2024: US$31.3
million).
The crude inventory movements represent the net movement of crude inventories
at year end against the beginning of the year which represent the production
cost excluding the depletion expenses portion as disclosed in Note 7.
Inventories written down represent reductions in carrying amount to net
realizable value, recognized as an expense during the year.
In 2024, the crude inventory movement included US$40.6 million of expense
subsequent to a lifting associated with the acquisition of the second tranche
of the CWLH Assets. The acquisition included 530,484 bbls of underlift at
closing at a fair market valuation of US$86.27/bbl, less 10% royalties and
approximately 1% in selling fees, totalling US$40.6 million as disclosed in
Note 19. The inventory was sold in March 2024. At the year end of 2024, CWLH
was in an underlift position of 386,451 bbls and accordingly has recognized a
credit of US$18.1 million.
Workovers in 2025 and 2024 were recurring in nature. The Group carried out a
lower number of workovers at Stag in 2025 in comparison to 2024.
Other repairs and maintenance in 2025 and 2024 include rectification costs of
the cranes and platform of Puteri Cluster SFA at PenMal, subsea maintenance at
Montara and fabric maintenance costs at Stag.
7. Depletion, depreciation and amortization ("DD&A")
2025 2024
US$'000 US$'000
Depletion and amortization (Note 21) 83,637 77,187
Depreciation of:
Plant and equipment (Note 22) 395 555
Right-of-use assets (Note 23) 12,273 16,195
Crude inventory movement 3,240 (2,530)
99,545 91,407
The crude inventory movement represents a addition or reversal of depletion
expense recognized during the year based on the net movement of crude
inventories at year end against beginning of the year. For the purpose of the
consolidated statement of cash flows, this amount has been excluded from the
movement in working capital.
8. Administrative staff costs
2025 2024
US$'000 US$'000
Wages, salaries and fees 18,376 20,272 42 (#_ftn42)
Staff benefits in kind 4,093 3,9271
Share-based compensation (Note 33) 1,312 407
23,781 24,606
The compensations of Directors and key management personnel are included in
the above and disclosed separately in Notes 10 and 47, respectively.
9. Staff numbers and costs
The monthly average number of employees (including Executive Directors) was:
2025 2024
Number Number
Production 156 159
Technical/Administrative 256 254
Management 9 9
421 422
Staff costs are allocated between production costs (Note 6) and administrative
staff costs (Note 8) Production costs include offshore personnel and technical
onshore office based staff directly supporting offshore operations.
Administrative staff costs comprise all onshore personnel at each of the
respective offices, covering roles that support the offshore operations and
administrative functions.
Their aggregate remuneration comprised:
2025 2024
US$'000 US$'000
Wages and salaries 52,752 51,750
Fees 549 701
Staff benefits in kind 4,348 3,697
Social security costs 271 233
Defined contribution pension costs 3,391 3,251
Share-based compensation (Note 33) 1,312 407
62,623 60,039
2025 2024
US$'000 US$'000
Contractors and consultants costs 5,362 5,011
67,985 43 (#_ftn43) 65,050
10. Directors' remuneration and transactions
2025 2024
US$'000 US$'000
Directors' remuneration
Salaries, fees, bonuses and benefits in kind 4,428 2,623
Amounts receivable under long-term incentive plans 521 233
Money purchase pension contributions 79 87
Compensation for loss of office - 2,464((a))
5,028 5,407
Number Number
The number of Directors who:
Are members of a money purchase pension scheme 2 2
Had awards receivable in the form of shares under a long-term 3 4
incentive scheme
( )
((a)) In 2024, the compensation for loss of office amounted to US$2.5 million,
including US$0.2 million of payroll tax for A. Paul Blakeley.
The non-executive Directors were not granted any options or shares under the
Group's long-term incentive plans.
For further details and details of remuneration of the highest paid Director,
please refer to Note 47.
11. Other expenses and allowance for expected credit losses
2025 2024
US$'000 US$'000
Corporate costs 13,952 13,840 44 (#_ftn44)
Allowance for slow moving inventories 1,072 1,670
Assets written off 8,664 1,775
Abandonment expenses 18,524 -
Net foreign exchange loss 2,133 2,008
Other expenses 5,324 4,444
49,669 23,737
Corporate costs represent the general and administrative expenses for the
Group which includes office expenses, professional fees, travel and
entertainment expenses.
Assets written off in 2025 represent the derecognition of US$8.6 million of
carrying amount of Montara non-depletable oil and gas properties, reflecting
the write-off of the original well cost following the successful side-track
that was completed during the year. In 2024, write-offs included the
de-recognition of US$1.4 million of Montara non-depletable oil and gas
properties following capitalization of replacement parts and US$0.4 million of
obsolete materials and spares.
Abandonment expenses of US$18.5 million were allocated to the SKUA-11 well,
which included a plug and abandonment phase as part of the programme to drill
a side-track well.
Other expenses mainly comprise withholding taxes, insurance expenses and other
miscellaneous expenses.
2025 2024
US$'000 US$'000
Allowance for expected credit losses (Note 28) 105 457
105 457
12. Auditor's remuneration
The analysis of the auditor's remuneration is as follows:
2025 2024
US$'000 US$'000
Fees payable to the Company's auditor for the audit of the parent Company and 778 668
Group's consolidated financial statements
Audit fees of the subsidiaries 597 519
1,375 1,187
No fee was paid to the Group's auditor for non-audit services for either the
Group or the Company in 2024 or 2025.
13. Impairment of assets
2025 2024
US$'000 US$'000
Impairment of oil and gas properties (Note 21) 126,040 -
The impairment expense for 2025 comprised of US$64.8 million and US$61.2
million relating to Stag and Montara's oil and gas properties, respectively.
Included within the impairment expense is Montara's 3D seismic study, which
was transferred from intangible exploration assets to oil and gas properties
and subsequently impaired.
The impairment was recognized following the Directors' assessment for
indicators of impairment in accordance with IAS 36. As impairment indicators
were identified, the recoverable amount of the operating asset was estimated
based on its value in use ("VIU"), using a discount rate of 10.0%.
The recoverable amount was lower than the carrying amount, resulting in the
recognition of an impairment expense. Further details of the impairment
assessment are disclosed in Note 4.
The key assumptions used in determining the VIU are disclosed Note 4(b). The
impairment is made in relation to the producing assets of the Group located in
Australia as disclosed in Note 45.
14. Other income
2025 2024
US$'000 US$'000
Interest income 7,645 7,492
Reversal of provisions:
Asset restoration obligations (Note 21 and Note 36) 3,679 13,824
Others (Note 36) - 1,112
Net foreign exchange gain 1,892 921
Gain on the sale of associate 17,518 -
Gain on hedge ineffectiveness of cash flow hedges 303 -
Rental income 4,483 5,731
Other income 4,199 -
Sundry income 430 534
40,149 29,614
15. Finance costs
2025 2024
US$'000 US$'000
Interest expense:
Lease liabilities 1,081 2,465
Standby working facility (Note 37) 883 1,483
RBL facility (Note 37) 18,928 16,428
Others 3,837 178
Accretion expense for:
Asset restoration obligations (Note 36) 28,223 22,544
Non-current Lemang PSC VAT receivables (1,156) 180
Upfront fees on financing facilities 600 867
Changes in fair value of:
Lemang PSC contingent payments (Note 36) - 53
RBL commitment fees (Note 37) - 142
Other finance costs 463 794
52,859 45,134
16. Other financial gains
2025 2024
US$'000 US$'000
Fair value gain on warrants (Note 42) 928 2,538
Fair value gain on derivative liability - 73
928 2,611
17. Income tax (credit)/expense
2025 2024
US$'000 US$'000
Current tax
Corporate tax expense 4,057 1,066
(Overprovision) in prior years of corporate tax (29) (468)
4,028 598
Australian petroleum resource rent tax ("PRRT") - (1,700)
Malaysian petroleum income tax ("PITA") 206 8,275
(Overprovision) in prior years of PRRT and PITA (5,772) -
(5,566) 6,575
Total current tax (1,538) 7,173
Deferred tax
Corporate tax (47,471) (1,548)
(Over)/underprovision in prior years of corporate deferred tax (13) 37
Gain on hedge ineffectiveness of cash flow hedges 91 -
(47,393) (1,511)
PRRT 21,817 (10,031)
PITA 1,156 5,473
Under/(overprovision) in prior years of deferred PRRT and PITA 3,032 (398)
26,005 (4,956)
Total deferred tax (21,388) (6,467)
Total tax (credit)/expenses (22,926) 706
Jadestone Energy plc is tax resident in Singapore and subject to the domestic
corporate tax rate of 17%, while its subsidiaries are taxed in the
jurisdictions in which they operate.
In Australia, corporate income tax is applied at 30% of taxable income, and
Petroleum Resource Rent Tax (PRRT) is levied at 40% of sales revenue less
permitted deductions and is itself tax deductible.
As at year end, the Montara and CWLH assets held unutilised carried forward
PRRT credits of US$4,516 million (2024: US$4,117 million) and US$814.4 million
(2024: US$802.4 million), respectively; based on the Directors' forecasts,
these accumulated PRRT losses are expected to exceed future taxable PRRT
profits, and therefore no PRRT expense is anticipated for these assets.
During the year, an overprovision of PRRT and Petroleum Income Tax (PITA) of
US$5.8 million (2024: US$Nil) was recognised, relating to Australian and
PenMal entities (US$3.2 million and US$2.6 million, respectively), primarily
arising from PRRT refunds, additional deductible repair and maintenance costs
and prior-year tax refunds, while the Stag asset recorded a net deferred PRRT
expense of US$21.8 million (2024: credit of US$11.7 million).
In Malaysia, corporate income tax is charged at 24% on non-petroleum income,
and PITA is levied at 38% of sales revenue less permitted deductions and is
tax deductible. The PenMal assets recorded a PITA expense of US$1.4 million
(2024: US$13.7 million).
At year end, tax recoverable of US$11.4 million (2024: US$13.8 million)
included a PITA receivable of US$1.5 million (2024: US$3.9 million) relating
to the pre-economic effective date of the PenMal acquisition, which will be
payable to SapuraOMV upon receipt of the refund, and a corresponding payable
has been recognised by the Group.
In Indonesia, corporate income tax is applied at 30% of taxable income, and
Corporate and Dividend Tax (C&D) is levied at 20% of sales revenue less
permitted deductions and is tax deductible; however, no Indonesian corporate
income tax expense was recognised for the Lemang asset as it remains in the
cost recovery phase and has not generated taxable income.
The tax expense on the Group's loss differs from the amount that would arise
using the standard rate of income tax applicable in the countries of operation
as explained below:
2025 2024
US$'000 US$'000
Loss before tax (133,673) (43,435)
Tax calculated at the domestic tax rates applicable to the profit/loss in the (39,830) (10,323)
respective countries (Australia 30%, Malaysia 24% & 38%, Canada 27%,
Singapore 17% and Indonesia 30%)
Effects of non-deductible expenses 3,502 839
Income not subject to tax (15,068) (1,897)
Effect of PRRT/PITA tax expense - 6,575
Deferred PRRT/PITA tax expense/(credit) 21,817 (4,558)
Deferred tax assets not recognized 9,827 10,899
Utilization of previously unrecognized tax losses (392) -
(Overprovision) of current tax in prior years (5,801) (468)
Under/(overprovision) of deferred tax in prior years 3,019 (361)
Tax (credit)/expense for the year (22,926) 706
Deferred tax assets amounting of US$9.8 million (2024: US$10.9 million) have
not been recognized in respect of losses as they may not be used to
offset taxable profits elsewhere in the Group. They have arisen in
subsidiaries that have been loss-making for some time, and there are no other
tax planning opportunities or other evidence of recoverability in the near
future.
In addition to the amount charged to the profit or loss, the following amounts
relating to tax have been recognized in other comprehensive income.
2025 2024
US$'000 US$'000
Other comprehensive income - deferred tax
Income tax expense related to carrying amount of hedged item 4,994 3,770
OECD Pillar Two model rules
The Group is within the scope of the Organisation for Economic Co-operation
and Development ("OECD") Pillar Two model rules. Pillar Two legislation was
enacted in the United Kingdom, the jurisdiction in which the Company is
incorporated, and is effective for accounting periods beginning on or after 31
December 2023.
The Company is tax resident in Singapore. Certain subsidiaries within the
Group operate in jurisdictions where Pillar Two legislation has been enacted
or substantively enacted as at 31 December 2025.
Under the legislation, the Group may be liable to pay top-up tax under the
Income Inclusion Rule ("IIR") in relevant jurisdictions, including the United
Kingdom, based on the difference between the Global Anti-Base Erosion
("GloBE") effective tax rate in each jurisdiction and the 15% minimum rate. In
addition, top-up taxes may be payable locally in jurisdictions where a
Qualified Domestic Minimum Top-up Tax ("QDMTT") has been enacted and is in
force.
The Group continues to assess the potential impact of the Pillar Two
legislation and, based on current assessments, does not expect material
exposure to Pillar Two income taxes in those jurisdictions. The Group has
applied the exception to recognizing and disclosing information about deferred
tax assets and liabilities related to Pillar Two income taxes, as provided in
the amendments to IAS 12 issued in May 2023.
18. Loss per ordinary shares
The calculation of the basic and diluted loss per share is based on the
following data:
2025 2024
US$'000 US$'000
Loss for the purposes of basic and diluted per share, being the net loss for (110,747) (44,141)
the year attributable to equity holders of the Company
2025 2024
Number Number
Weighted average number of ordinary shares for the purposes of 541,148,265 540,848,891
basic EPS
Weighted average number of ordinary shares for the purposes of 541,148,265 540,848,891
dilutive EPS
In 2025, none (2024: 47,139) of the weighted average potentially dilutive
ordinary shares available for exercise from in the money vested options,
associated with share options were excluded from the calculation of diluted
EPS, as they are anti-dilutive in view of the loss for the year.
In 2025, 397,524 (2024: 53,106) of the weighted average contingently issuable
shares associated under the Company's performance share plan based on the
respective performance measures up to year end were excluded from the
calculation of diluted EPS, as they are anti-dilutive in view of the loss for
the year.
In 2025, 5,665,262 (2024: 293,655) of the weighted average contingently
issuable shares under the Company's restricted share plan were excluded from
the calculation of diluted EPS, as they are anti-dilutive in view of the loss
for the year.
In 2025, 30,000,000 (2024: 30,000,000) of the weighted average contingently
issuable shares under the Company's warrants instrument were excluded from the
calculation of diluted EPS, as they are anti-dilutive in view of the loss for
the year.
Loss per share (US$) 2025 2024
· Basic and diluted (0.20) (0.08)
19. Acquisitions
19.1 Acquisition of interest in CWLH joint operation
a. 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 "North West Shelf Project" or "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 of trade
and other receivables movement.
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.
b. 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.
c. Fair value of consideration
After taking into account various adjustments the net consideration for the
CWLH Assets resulted in a cash receipt of US$5.2 million, as set out below:
US$'000
Asset purchase price 9,000
Closing statement adjustments 45 (#_ftn45) (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.
d. Assets acquired and liabilities assumed at the date of acquisition
In 2024, 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. No
changes were made in 2025.
Below are the effects of final PPA adjustments in accordance with IFRS 3:
PPA
US$'000
Asset
Non-current asset
Oil and gas properties (Note 21) 118
Deferred tax assets 19,763
Current asset
Amount due from joint arrangement partner 194
Trade and other receivables 40,602 46 (#_ftn46)
60,677
PPA
US$'000
Liabilities
Non-current liabilities
Provision for asset restoration obligations (Note 36) 65,881
Deferred tax liabilities 32
65,913
Net identifiable liabilities assumed (5,236)
e. Impact of acquisition on the results of the Group
The Group's 2024 results included US$56.4 million of revenue and US$2.0
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$2.0 million after tax loss.
20. Intangible explorations assets
US$'000
Cost
As at 1 January 2024 79,564
Additions 11,759((a)(b))
As at 31 December 2024 91,323
Additions 2,389
Transfer (Note 21) (2,092)((c))
As at 31 December 2025 91,620
Carrying amount
As at 31 December 2024 91,323
As at 31 December 2025 91,620
No impairment losses were recognized on intangible assets during the year
ended 31 December 2025.
((a)) In 2024, the additions include US$10.0 million arising from provision
for commitment to drill one exploration well in Nam Du gas field in Block
46/07. For further information, please refer to Note 36.
((b)) For the purpose of the consolidated statement of cash flows, current
year expenditure on intangible exploration assets of US$0.6 million remained
unpaid as at 31 December 2025 (2024: US$10.2 million).
((c)) During 2025, the Group transferred US$2.1 million from intangible
exploration assets to oil and gas properties as disclosed in Note 21 relating
to 3D seismic study performed in 2020 and associated with the SKUA-11 side
track well drilled in 2025. The amount was subsequently fully impaired during
the year as disclosed in Note 13.
21. Oil and gas properties
Production assets Development assets
Total
US$'000 US$'000 US$'000
Cost
As at 1 January 2024 774,012 122,624 896,636
Changes in asset restoration obligations (Note 36)
(20,025) 1,330 (18,695)((a))
Additions 19,281 42,943 62,224((b))
Acquisition of additional interest of CWLH Assets (Note 19)
118 - 118
Written off (2,965) - (2,965)
Reclassification 166,897((c)) (166,897)((c)) -
As at 31 December 2024 937,318 - 937,318
Changes in asset restoration obligations (Note 36)
9,229 - 9,229((a))
Additions 90,347 - 90,347((b))
Written off (8,664) - (8,664)
Transfer (Note 20) 2,092 - 2,092((d))
As at 31 December 2025 1,030,322 - 1,030,322
Accumulated depletion, amortization and
impairment
As at 1 January 2024 439,434 - 439,434
Charge for the year (Note 7) 77,187 - 77,187
Written off (1,542) - (1,542)
As at 31 December 2024 515,079 - 515,079
Charge for the year (Note 7) 83,637 - 83,637
Impairment (Note 13) 126,040 - 126,040((e))
As at 31 December 2025 724,756 - 724,756
Carrying amount
As at 31 December 2024 422,239 - 422,239
As at 31 December 2025 305,566 - 305,566
((a)) The changes in ARO in Note 36 of US$5.5 million 2024: (US$32.5 million)
is a net of recognition in other income of US$3.7 million (2024: US$13.8
million) in Note 14. No capitalization in oil and gas properties were recorded
in 2025 (2024: US$18.7 million)
((b)) For the purpose of the consolidated statement of cash flows, current
year expenditure on oil and gas properties of US$9.2 million remained unpaid
as at 31 December 2025 (2024: US$8.7 million). No capitalization of borrowing
costs of were recorded in 2025 (2024: US$5.1 million).
((c)) On 31 July 2024, the Group successfully commenced operations of the
Akatara Gas Processing Facility producing gas, LPG, and condensate.
Accordingly, all oil and gas properties under development were reclassified to
production assets.
((d)) During 2025, the Group transferred US$2.1 million from intangible
exploration assets as disclosed in Note 20 to oil and gas properties related
to 3D seismic study performed in 2020 and associated with SKUA-11 side track
well drilled in 2025. The amount was subsequently fully impaired during the
year as disclosed in Note 13.
((e)) In 2025, impairment expenses of US$64.8 million and US$61.2 million were
recognized for Stag's and Montara's oil and gas properties, respectively as
further disclosed in Note 13.
22. Plant and equipment
Computer equipment Fixtures and fittings Materials and spares
US$'000 US$'000 US$'000
Total
US$'000
Cost
As at 1 January 2024 3,725 1,945 9,158 14,828
Additions 446 30 - 476
Transfer - - 208 208((a))
As at 31 December 2024 4,171 1,975 9,366 15,512
Additions 42 29 - 71
Foreign exchange differences (7) - - (7)
Transfer - - 243 243((a))
As at 31 December 2025 4,206 2,004 9,609 15,819
Accumulated depreciation
As at 1 January 2024 2,655 1,711 - 4,366
Charge for the year (Note 7) 429 126 - 555
As at 31 December 2024 3,084 1,837 - 4,921
Charge for the year (Note 7) 319 76 - 395
As at 31 December 2025 3,403 1,913 - 5,316
Carrying amount
As at 31 December 2024 1,087 138 9,366 10,591
As at 31 December 2025 803 91 9,609 10,503
((a)) The transfer represents the material and spares that are not expected to
be consumed within the next 12 months from the year end. The reclassification
amount is net of allowance of slow-moving items of US$0.8 million (2024:
US$0.5 million).
23. Right-of-use assets
Transportation and logistics Buildings
US$'000 US$'000 Total
US$'000
Cost
As at 1 January 2024 43,353 4,874 48,227
Additions 1,122 85 1,207
Derecognition (5,117) - (5,117)
As at 31 December 2024 39,358 4,959 44,317
Additions 13,272 1,283 14,555
Lease modification((a)) 25,631 - 25,631
Derecognition (3,782) (582) (4,364)
As at 31 December 2025 74,479 5,660 80,139
Accumulated depreciation
As at 1 January 2024 14,203 2,925 17,128
Charge for the year (Note 7) 15,297 898 16,195
Derecognition (5,117) - (5,117)
As at 31 December 2024 24,383 3,823 28,206
Charge for the year (Note 7) 11,431 842 12,273
Derecognition (3,107) (582) (3,689)
As at 31 December 2025 32,707 4,083 36,790
Carrying amount
As at 31 December 2024 14,975 1,136 16,111
As at 31 December 2025 41,772 1,577 43,349
((a) ) In 2025, the Group executed a revised lease agreement for an extension
of the lease term. This was accounted for as a lease modification in
accordance with IFRS 16, resulting in a remeasurement of the lease liability
with a corresponding adjustment to the right-of-use asset. The adjustment to
the right-of-use asset is recognized as an adjustment to the asset's carrying
amount and is depreciated prospectively over the revised lease term.
Most of the Group's right-of-use assets are contracts to lease assets
including helicopters, a supply boat and logistic facilities for the Montara
field and buildings. The average lease term is 3.2 years (2024: 2.8 years).
The additions to right-of-use assets during the year mainly consist of the
extension on both of the buildings and transportation and logistics assets.
The maturity analysis of lease liabilities is presented in Note 38.
2025 2024
US$'000 US$'000
Amount recognized in profit or loss
Depreciation expense on right-of-use assets (Note 7) 12,273 16,195
Interest expense on lease liabilities (Note 15) 1,081 2,465
Expenses relating to short-term leases 21,493 31,451
Expense relating to leases of low value assets 321 292
As at 31 December 2025, the Group is committed to US$2.1 million (2024: US$6.3
million) of short-term leases.
The total cash outflow in 2025 relating to leases was US$59.7 million (2024:
US$50.7 million).
24. Investment in associates
2025 2024
US$'000 US$'000
At beginning of year 19,544 26,651
Dividends received during the year - (8,660)
Share of profit of the associate 1,849 1,553
Disposal of associate at carrying amount (21,393) -
At end of year - 19,544
On 16 April 2025, the Group 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.
The Group accounted for its investment in APICO LLC using the equity method up
until 16 April 2025. The Group had significant influence over APICO LLC by
having the power to participate in the financial and operating policy
decisions of the entity. As a result, the Group had an effective 9.52%
non-operated interest in the Sinphuhorm gas field through its investment in
APICO LLC.
APICO LLC is a 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.
25. Interest in operations
Details of the operations, of which all are in production except for 46/07,
51, Puteri Cluster and PM428 which are in the exploration stage, are as
follows:
Place of Group effective working interest % as at 31 December((c))
Contract Area Date of expiry Held by operations 2025 2024
Montara Oilfield Indefinite Jadestone Energy (Eagle) Australia 100 100
Pty Ltd
Stag Oilfield 25 August 2039 Jadestone Energy (Australia) Pty Ltd Australia 100 100
PM329 ((a)) 8 December 2031 Jadestone Energy (Malaysia) Pte Ltd Malaysia 60 70
PM329 ((a)) 8 December 2031 Jadestone Energy (PM) Inc. Malaysia 10 -
PM323 14 June 2028 Jadestone Energy (Malaysia) Pte Ltd Malaysia 60 60
Puteri Cluster SFA
30 June 2038 Jadestone Energy (PM) Inc. Malaysia 100 100
PM428 21 April 2053 Jadestone Energy (PM) Inc. Malaysia 100 100
WA-3-L Indefinite Jadestone Energy (CWLH) Pty Ltd Australia 33 33
WA-9-L 15 July 2033 Jadestone Energy (CWLH) Pty Ltd Australia 33 33
WA-11-L 4 September 2035 Jadestone Energy (CWLH) Pty Ltd Australia 33 33
WA-16-L 11 September 2039 Jadestone Energy (CWLH) Pty Ltd Australia 33 33
46/07 29 June 2035 Mitra Energy (Vietnam Nam Du) Pte Ltd Vietnam 100 100
51 10 June 2040 Mitra Energy (Vietnam Tho Chu) Pte Ltd Vietnam 100 100
Lemang 17 January 2037 Jadestone Energy (Lemang) Pte Ltd Indonesia 100 100
Sinphuhorm concession (E5N)((b)) 15 March 2031 Jadestone Energy (Thailand) Pte Ltd Thailand - 10
Sinphuhorm concessions (EU1)((b)) 2 June 2029 Jadestone Energy (Thailand) Pte Ltd Thailand - 10
Dong Mun (L27/43)((b)) 24 September 2017 Jadestone Energy (Thailand) Pte Ltd Thailand - 27
((a)) On 31 December 2025, Jadestone Energy (Malaysia) Pte Ltd ("JEM") entered
into a Deed of Assignment with Jadestone Energy (PM) Inc ("JEPM") to transfer
a 10% of participating interest in the PM329 asset to JEPM.
( )
((b)) On 16 April 2025, the Group entered into a sale and purchase agreement
to sell Jadestone Energy (Thailand) Pte Ltd and its interest in the Sinphuhorm
gas field as further disclosed in Note 24.
((c)) The Group's effective working interest percentage as at 31 December
reflects its share of participation in each asset, based on contractual
arrangements in place at the reporting date. These percentages are used to
determine the Group's proportionate recognition of related financial statement
items.
26. Deferred tax
The following are the deferred tax liabilities and assets recognized by the
Group and movements thereon.
Australian PRRT Malaysian PITA Tax depreciation Derivative financial instruments
US$'000 US$'000 US$'000 US$'000
Total
US$'000
As at 1 January 2024 5,582 (550) (50,143) 6,056 (39,055)
Credited/(charged) to profit or loss (Note 17) 10,031 (5,473) 1,909 - 6,467
Credited to OCI - - - (3,770) (3,770)
Acquisition of additional interest of CWLH Assets (Note 19) - - 19,731 - 19,731
Reclassification of carried forward business losses - - 1,905 - 1,905
As at 31 December 2024 and 1 January 2025 15,613 (6,023) (26,598) 2,286 (14,722)
Credited/(charged) to profit or loss (Note 17) (21,817) (1,156) 44,452 (91) 21,388
Credited to OCI - - - (4,994) (4,994)
Reclassification of carried forward business losses - - 284 - 284
As at 31 (6,204) (7,179) 18,138 (2,799) 1,956
December 2025
The following is the analysis of the deferred tax balances (after offset) 47
(#_ftn47) for financial reporting purposes:
2025 2024
US$'000 US$'000
Deferred tax liabilities (18,650) (59,620)
Deferred tax assets 20,606 44,898
1,956 (14,722)
The Group's deferred tax assets predominately arising from its Australian
operations and PenMal Assets. Deferred tax assets are recognized as the
Directors believe there will be sufficient taxable profits from its Australian
and Malaysian producing assets to offset against the available future
deductions based on the estimated future cash flows prepared.
There is no deferred tax asset recognized at Akatara due to the structure of
the PSC and its cost recovery mechanism. Under the PSC terms, operating losses
carried forward are recovered directly through the cost recovery process
rather than through future tax savings. Since acquiring the Lemang PSC in
2020, accumulated losses have been added to the cost recovery pool, which will
be reimbursed from future production entitlements.
As of first gas on 1 July 2024, the cost recovery pool stood at US$288.0
million. These historical losses are recovered through production which is not
taxable until the cost recovery pool is fully depleted. The PSC will only
generate income tax after the cost recovery pool is fully depleted and so
there is not sufficient certainty that future profits will be generated
against which to utilize the losses.
The Group has unutilized PRRT credits of approximately US$4,516 million (2024:
US$4,117 million) and US$814.4 million (2024: US$802.4 million) available for
offset against future PRRT taxable profits in respect of the Montara field and
the CWLH Assets, respectively. The PRRT credits remain effective throughout
the production license of Montara and the CWLH Assets. No deferred tax asset
has been recognized in respect of these PRRT credits, due to the Directors'
projections that the historic accumulated PRRT net losses are larger than
cumulative future expected PRRT taxable profits. As PRRT credits are utilized
based on a last-in-first-out basis, the unutilized PRRT credits of
approximately US$4,516 million (2024: US$4,117 million) and US$814.4 million
(2024: US$802.4 million) with respect to Montara and the CWLH Assets are not
expected to be utilized and are therefore not recognized as a deferred tax
asset.
27. Inventories
2025 2024
US$'000 US$'000
Materials and spares 33,221 30,164
Less: allowance for slow moving (10,700) (9,960)
22,521 20,204
Crude oil inventories 19,430 24,398
41,951 44,602
The cost of inventories of US$291.6 million (2024: US$333.0 million)
recognized as an expense during the year for lifted volume, is calculated by
including production costs excluding workovers, Malaysian supplementary
payments and tariffs and transportation costs, plus depletion expense of oil
and gas properties, and plus depreciation of right-of-use assets deployed for
operational use.
28. Trade and other receivables
2025 2024
US$'000 US$'000
Current assets
Trade receivables 30,523 15,846
Prepayments 2,281 8,459
Other receivables 12,099 7,731
Amount due from joint arrangement partners 1,807 2,390
Underlift crude oil inventories 14,410 12,278
GST/VAT receivables 6,911 8,797
68,031 55,501
Allowance for expected credit loss (Note 11) (562) (457)
67,469 55,044
Non-current assets
Other receivables 258,525 261,517
GST/VAT receivables 15,090 12,607
273,615 274,124
341,084 329,168
Set out below is the movement in the allowance for expected credit losses of
trade receivables:
2025
US$'000
As at 1 January 2025 457
Allowance for expected credit losses (Note 11) 105
As at 31 December 2025 562
Trade receivables arise from revenues generated from operations in Australia,
Malaysia and Indonesia. The average credit period is 30 days (2024: 30 days).
The Group has recognized an allowance for expected credit losses of US$0.1
million (2024: US$0.5 million) and remaining outstanding receivables as at 31
December 2025 and 2024 have been recovered in full in 2026 and 2025,
respectively.
Amount due from joint arrangement partners represents cash calls receivable
from the Malaysian joint arrangement partner, net of joint arrangement
expenditures. The amount is unsecured, with a credit period of 15 days. A
notice of default will be served to the joint arrangement partner if the
credit period is exceeded, which will become effective seven days after
service of such notice if the outstanding amount remains unpaid. Interest of
3% per annum will be imposed on the outstanding amount, starting from the
effective date of default. The outstanding receivable was subsequently
received in February 2026.
The underlift crude oil inventories represent entitlement imbalances at year
end of 86,653 bbls and 358,231 bbls at the PenMal operated assets and CWLH
Assets measured at cost of US$20.64/bbl and US$35.37/bbl respectively. The
2025 underlift position will unwind in 2026 based on the subsequent net
productions entitled to the Group.
As at 31 December 2025, the Group recognized a total of US$168.1 million in
relation to the CWLH trust fund, comprising current other receivables of
US$4.4 million and non-current other receivables of US$163.7 million. The
Group also recognized non-current receivables of US$93.9 million relating to
accumulated cess payments made to the Malaysian regulators for the operated
licenses, and US$0.8 million relating to accumulated cess payments made to the
Indonesian regulators for the operated licenses.
The Malaysian PSCs and Lemang PSC require upstream operators to contribute
periodic cess payments to a cess abandonment fund throughout the production
life of the upstream oil and gas assets.
The CWLH trust fund is held under a trust arrangement in accordance with the
CWLH Project Plan and Deed of Consent. The trust comprises a single bank
account operated and controlled by the trustee, Woodside Energy (the
Operator). The trust fund is administered by the trustee in accordance with
the Project Plan and the Group is not a signatory to the bank account and does
not have direct access to, or control over, the funds, nor the ability to
influence their day-to-day use. The funds are contractually restricted to
decommissioning activities and may only be used subject to joint venture
approval.
The majority of decommissioning activities are currently expected to occur
from 2035 onwards.
Based on current estimates, the fair value of the associated asset retirement
obligation (ARO) is approximately $126.8 million, which is expected to be
settled by the trust fund. The remaining balance of approximately $41.3
million is anticipated to be refundable to the Group following the completion
of decommissioning activities and full settlement of all related costs,
subject to final outcomes. The surplus is maintained as a contingency buffer
to absorb potential escalations in future decommissioning cost estimate.
The receivable is classified as non-current given the expected timing of use
and/or recovery, consistent with the long-term nature of the decommissioning
schedule.
In 2024, the non-current other receivables included the abandonment trust fund
as described above and as disclosed in Note 19, plus the reclassification of
Puteri Cluster cess fund of US$47.8 million from current to non-current.
There are no trade receivables older than 30 days other than those for which
an allowance for expected credit losses has been recognized. The credit risk
associated with the trade receivables is disclosed in Note 43.
29. Cash and bank balances
2025 2024
US$'000 US$'000
Cash and bank balances, representing cash and cash equivalents in the
consolidated statement of cash flows, presented as:
Non-current 310 888
Current 60,606 94,338
60,916 95,226
The non-current cash and cash equivalents represent the restricted cash
balance of US$Nil (2024: US$0.6 million) and US$0.3 million (2024: US$0.3
million) in relation to a deposit placed for bank guarantee with respect to
the PenMal Assets and Australian office building, respectively. These deposits
placed for bank guarantees are expected to be in place for a period of more
than twelve months, but allows withdrawal on demand within three months
without penalty as at 31 December 2025.
Current cash and cash equivalents include a bank guarantee of US$0.3 million
(2024: US$0.3 million) and US$3.6 million (2024: US$3.0 million) placed by the
Group during the year with respect to the construction of the Lemang PSC gas
pipeline facilities and PenMal Assets. These deposits placed for bank
guarantees are expected to be in place for a period of less than twelve
months, but allows withdrawal on demand within three months without penalty as
at 31 December 2025.
As part of the RBL facility, the Group must retain an aggregate amount of
principal, interest, fees and costs payable for the next two quarters in the
debt service reserve account ("DSRA"). As at 31 December 2025, the DSRA
contained US$2.4 million (2024: US$8.2 million).
30. Share capital and share premium account
Share capital Share premium account
No. of shares US$'000 US$'000
Issued and fully paid
As at 1 January 2024, at £0.001 each 540,766,574 456 51,827
Issued during the year 344,225 1 349
As at 31 December 2024 541,110,799 457 52,176
Issued during the year (Note 33) 1,051,916 1 329
As at 31 December 2025 542,162,715 458 52,505
During the year, no (2024: nil) share options were exercised and issued.
Additionally, 1,051,916 shares (2024: 344,225 shares) were issued to meet the
obligations with regards to the restricted shares 48 (#_ftn48) .
The Company has one class of ordinary share. Fully paid ordinary shares with
par value of GB£0.001 per share carry one vote per share without restriction
and carry a right to dividends as and when declared by the Company.
31. Dividends
The Company did not declare any dividend during the year (2024: US$nil).
32. 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.
33. Share-based payments reserve
Share-based payments reserve represents the cumulative value of share-based
payment expenses recognized in relation to equity-settled option granted under
the Group's share-based compensation schemes. The reserve is transferred to
share capital or retained earnings, as applicable, upon the exercise, lapse,
or cancellation of the related share-based instruments.
The total expense arising from share-based payments of US$1.3 million (2024:
US$0.4 million) was recognized as 'administrative staff costs' (Note 8) in
profit or loss for the year ended 31 December 2025.
During the year, US$0.3 million (2024: US$0.3 million) of restricted shares
was vested and has been reclassified from share-based payments reserve to
share capital as shown in Note 30.
The share-based payment expense during the year arose from share options,
performance shares and restricted shares 49 (#_ftn49) were awarded from 2022
to 2025.
In 2023 and 2024, the performance share grants were suspended by the
Remuneration Committee upon the Committee's recommendation. In consultation
with external advisor, the Remuneration Committee approved a Deferred Cash
Plan ("DCP") as part of the Long-Term Incentive ('LTI") cycle.
This was done to ensure that the LTI programme aligns the interests of the
senior leaders of the Group to the interests of shareholders and is effective
in retaining and incentivising our top talent.
DCP was awarded in October 2023 and April 2024, with a three-year vesting
period ending in 2026 and 2027, respectively. The performance measures for the
DCP are consistent with those applied to the performance shares. DCP has been
recognized in liabilities as disclosed in Note 40.
On 15 May 2019, the Company adopted, as approved by the shareholders, the
amended and restated stock option plan, the performance share plan, and the
restricted share plan (together, the "LTI Plans"), which establishes a rolling
number of shares issuable under the LTI Plans up to a maximum of 10% of the
Company's issued and outstanding ordinary shares at any given time. Options
under the stock option plan will be exercisable over periods of up to 10 years
as determined by the Board.
During the year, the Group has granted new share options, performance shares
and restricted shares as further disclosed below.
33.1 Share options
The Directors have applied the Black-Scholes option-pricing model, with the
following assumptions, to estimate the fair value of the options at the date
of grant:
Options granted on
20 November 2025 9 March 2022
Risk-free rate 3.95% to 4.07% 1.34% to 1.38%
Expected life 4.5 to 5.5 years 5.5 to 6.5 years
Expected volatility 50 (#_ftn50) 49.2% to 50.1% 63.0% to 66.7%
Share price GB£ 0.24 GB£ 1.01
Exercise price GB£ 0.24 GB£ 0.92
Expected dividends 0.00% 1.96%
33.2 Performance shares
In 2022, the performance measures for performance shares incorporate both a
relative and absolute total shareholder return ("TSR") calculation on a 70:30
basis to compare performance vs. peers (relative TSR) and to ensure alignment
with shareholders (absolute TSR).
During the year, the performance measures for performance shares incorporate a
TSR calculation and the Group's Environmental, Social, and Governance ("ESG")
performance on 65:35 basis.
Relative TSR: measured against the TSR of peer companies; the size of the
payout is based on Jadestone's ranking against the TSR outcomes of peer
companies.
Absolute TSR: share price target plus dividend to be set at the start of the
performance period and assessed annually; the threshold share price plus
dividend has to be equal to or greater than a 10% increase in absolute terms
to earn any pay out at all, and must be 25% or greater for target pay out.
A Monte Carlo simulation model was used by an external specialist, with the
following assumptions to estimate the fair value of the performance shares at
the date of grant:
Performance shares granted on
20 November 2025 9 March 2022
Risk-free rate 3.67% 1.39%
Expected volatility 51 (#_ftn51) 42.3% 53.1%
Share price GB£ 0.24 GB£ 1.01
Exercise price N/A N/A
Expected dividends 0.00% 1.71%
Post-vesting withdrawal date N/A N/A
Early exercise assumption N/A N/A
33.3 Restricted shares 52 (#_ftn52)
Restricted shares are granted to certain senior management personnel as an
alternative to cash under exceptional circumstances and to provide greater
alignment with shareholder objectives. These are shares that vest three years
after grant, assuming the employee has not left the Group. They are not
eligible for dividends prior to vesting.
The following assumptions were used to estimate the fair value of the
restricted shares at the date of grant, discounting back from the date they
will vest and excluding the value of dividends during the intervening period:
Restricted shares granted on
5 December 2025 20 November 2025 17 February 2025 29 January 2025 6 December 2024
2 June 2025 22 May 2025 22 August 2022 9 March 2022
Risk-free rate N/A N/A N/A N/A N/A N/A 3.67% 1.73% 1.39%
Share price GB£ 0.24 GB£ 0.24 GB£ 0.20 GB£ 0.21 GB£ 0.30 GB£ 0.90 GB£ 0.27 GB£ 0.90 GB£ 1.01
Expected dividends 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 1.73% 1.71%
The following table summarizes the options/shares under the LTI plans
outstanding and exercisable as at 31 December 2025:
Share Options
Performance shares Restricted shares
Weighted average Weighted
exercise average Number
Number of options price GB£ remaining of options exercisable
contract life
As at 1 January 2024 2,217,103 344,225 19,266,121 0.48 5.37 16,508,516
Vested during the year - (344,225) - 0.76 7.19 2,118,585
Expired unexercised during the year (967,794) - (125,418) 0.59 - (125,418)
Granted during the year - 1,242,000 - - - -
As at 31 December 2024 1,249,309 1,242,000 19,140,703 0.45 4.67 18,501,683
Vested during the year - (1,051,916) - 0.85 3.95 1,334,979
Expired unexercised during the year - - - - - -
Cancelled during the year (49,544) - (8,249,247) - - (8,249,247)
Granted during the year 2,494,608 10,233,438 1,885,979 - - 1,885,979
As at 31 December 2025 3,694,373 10,423,522 12,777,435 0.48 4.72 13,473,393
The weighted average share price on the exercise date in 2025 was GB£0.22.
Weighted average Weighted
Range of exercise average
exercise price GB£ remaining
Number of options price contract life
GB£
Share options exercisable as at 31 December 2024 18,501,683 0.26 - 0.99 0.45 4.67
Share options exercisable as at 31 December 2025 13,473,393 0.24 - 0.99 0.48 4.72
34. Capital redemption reserve
The capital redemption reserve arose from the programme launched by the
Company in August 2022. It represents the par value of the shares purchased
and cancelled by the Company under the Programme (Note 30).
35. Hedging reserve
2025 2024
US$'000 US$'000
At beginning of the year (5,333) (14,131)
Gain/(loss) arising on changes in fair value of hedging instruments during the 18,866 (14,849)
year
Income tax related to gain/loss recognized in other comprehensive income
(5,660) 4,455
Net (gain)/loss reclassified to profit or loss (Note 5) (2,220) 27,417
Income tax related to amounts reclassified to profit or loss 666 (8,225)
At end of the year 6,319 (5,333)
The hedging reserve represents the cumulative amount of gains and losses on
hedging instruments deemed effective in cash flow hedges. The cumulative
deferred gain or loss on the hedging instrument is recognized in profit or
loss only when the hedged transaction impacts the profit or loss. See Note 41
for further details on the hedging arrangements.
36. Provisions
Asset restoration obligations((a))
US$'000 Contingent payments((b)) Employees benefits((c))
US$'000 US$'000 Others Total
US$'000 US$'000
As at 1 January 2024 603,902 5,647 1,034 1,112 611,695
Credited to profit or loss - - - (1,112)((e)) (1,112)((e))
Accretion expense (Note 15) - - -
22,544 22,544
Change in estimation (Notes 14 and 21)
(32,518) - - - (32,518)
Payment/Utilization - (5,000) (12) - (5,012)
Fair value adjustment - Lemang PSC (Note 15)
- 53 - - 53
Acquisition of additional interest of CWLH Assets (Note 19)
- - -
65,881 65,881
Additions during the year (Note 20) - -
- 10,000((f)) 10,000((f))
Reclassification (1,038)((d)) - - - (1,038)((d))
As at 31 December 2024 and 1 January 2025 658,771 700 1,022 10,000 670,493
Accretion expense (Note 15)
28,223 - - - 28,223
Change in estimation (Notes 14 and 21)
5,550 - (318) - 5,232
Payment/Utilization - - (110) (110)
Additions during the year - - 283 3,692((g)) 3,975
Reclassification (271)((d)) - - - (271)((d))
As at 31 December 2025 692,273 700 877 13,692 707,542
As at 31 December 2024
Current 4,109 700 733 - 5,542
Non-current 654,662 - 289 10,000 664,951
658,771 700 1,022 10,000 670,493
As at 31 December 2025
Current 4,335 700 517 3,692 9,244
Non-current 687,938 - 360 10,000 698,298
692,273 700 877 13,692 707,542
((a) ) The Group's ARO comprise the future estimated costs to
decommission each of the Montara, Stag, Lemang PSC, PenMal Assets and CWLH
Assets.
The carrying value of the provision represents the discounted present value of
the estimated future costs. Current estimated costs of the ARO for each of the
Montara, Stag, Lemang PSC, PenMal Assets and CWLH Assets have been escalated
to the estimated date at which the expenditure would be incurred, at an
assumed blended inflation rate. The estimates for each asset are a blend of
assumed US and respective local inflation rates to reflect the underlying mix
of US dollar and respective local dollar denominated expenditures. The present
value of the future estimated ARO for each of the Montara, Stag, Lemang PSC,
PenMal Assets and CWLH Assets has then been calculated based on a blended
risk-free rate. The base estimate ARO for Montara Stag, Lemang PSC and PenMal
Assets remains largely unchanged from 2024. There is a US$16.9 million
increase in base estimates for CWLH due to the updated Operator ARO provision.
The blended inflation rates and risk-free rates used, plus the estimated
decommissioning year of each asset are as follows:
No. Asset Blended inflation rate Blended risk-free rate Estimated decommissioning year
2025 2024 2025 2024
1. Montara 2.43% 2.40% 4.04% 4.32% 2031
2. Stag 2.32% 2.30% 4.33% 4.60% 2036
3. Lemang PSC
2.50% 2.45% 5.70% 6.45% 2036
4. PenMal Assets 3.00% - 3.42% 3.67% - 3.89%
2.08% 2.15% 2027 onwards
5. CWLH Assets
2.44% 2.41% 4.52% 4.51% 2037
Following the enactment of the Offshore Petroleum and Greenhouse Gas Storage
Amendment (Titles Administration and Other Measures) Act 2021 which, amongst
other things, enhanced the decommissioning framework applying to offshore
assets in Australia, on 29 March 2023 Jadestone Energy (Australia) Pty Ltd,
Jadestone Energy (Eagle) Pty Ltd and Jadestone Energy (CWLH) Pty Ltd, each
wholly owned subsidiaries of the Company, entered into a deed poll with the
Australian Government with regard to the requirements of maintaining
sufficient financial capacity to ensure that each of Montara's, Stag's and
CWLH's asset restoration obligations can be met when due. The deed states that
the Group is required to provide financial security in favor of the Australian
Government when the aggregate remaining net after-tax cash flow of the Group
is below 1.25 times of the Group's estimated decommissioning liabilities net
of any residual value, tax benefits, and other financial assurance committed
by the Group for such purposes. The Group does not expect to provide financial
security under the deed poll based on the financial capacity assessment.
The Malaysian and Indonesian regulators require upstream oil and gas companies
to contribute to an abandonment cess fund, including making monthly cess
payments, throughout the production life of the oil or gas field. The cess
payment amount is assessed based on the estimated future decommissioning
expenditures. The cess payment paid for non-operated licenses reduces the ARO
liability. The Malaysian abandonment cess fund only covers the decommissioning
costs related to the oil and gas facilities, excluding wells. The Indonesian
cess fund covers the decommissioning costs related to all facilities. The
Group has recognized ARO provisions for the estimated decommissioning costs of
the wells in the PSCs.
An abandonment trust fund was set as part of the acquisition of the CWLH
Assets to ensure there are sufficient funds available for decommissioning
activities at the end of field life. The cash contribution paid into the
trust fund is classified as other receivables as disclosed in Note 28 as the
amount is reclaimable by the Group in the future following the commencement of
decommissioning activities.
((b) ) The fair value of the contingent payments payable to Mandala
Energy Lemang Pte Ltd for the Lemang PSC acquisition are valued at US$0.7
million as at 31 December 2025 (2024: US$0.7 million) for the trigger events
as disclosed below. The balance remains unchanged during the year as there
were no revisions to the underlying assumptions and no remeasurement of the
contingent consideration.
No. Trigger event Consideration Directors' rationale
1. First gas date US$5.0 million The first gas date was on 31 July 2024 and this has been paid on 17 September
2024.
2. The accumulated VAT receivables reimbursements which are attributable to the US$0.7 million The Directors estimated that the accumulated receipts of VAT reimbursements
unbilled VAT in the Lemang Block as at the Closing Date, exceeding an received will exceed US$6.7 million on a gross basis and expected to be
aggregate amount of US$6.7 million on a gross basis received within next 12 months.
3. First gas date on or before 31 March 2023 US$3.0 million Not payable as the trigger event has expired. First gas occurred on 31 July
2024
4. Total actual Akatara Gas Project "close out" costs set out in the AFE(s) US$3.0 million Based on the status of the Akatara Gas Project as at 2025 year end, the actual
approved pursuant to a joint audit by SKK MIGAS and BPKP is less than, or "close out" costs set out in the AFE(s) has exceeded the "close out"
within 2% of the "close out" development costs set out in the approved revised development costs set out in the approved revised plan by more than 2%. As
plan of development for the Akatara Gas Project such, the consideration trigger will not be met.
5. The average Saudi CP in the first year of operation is higher than US$620/MT US$3.0 million Not payable as the price was below US$620/MT during the first year of
operation.
6. The average Saudi CP in the second year of operation is higher than US$620/MT US$2.0 million Not payable as the price was below US$620/MT during the second year of
operation.
No. Trigger event Consideration Directors' rationale
7. The average Dated Brent price in the first year of operation is higher than US$2.5 million Not payable as the price was below US$80/bbl during the first year of
US$80/bbl operation.
8. The average Dated Brent price in the second year of operation is higher than US$1.5 million Not payable as the price was below US$80/bbl during the second year of
US$80/bbl operation.
9. A plan of development for the development of a new discovery made, as a result US$3.0 million There are no prospects or leads presently selected for the exploration well
of the remaining exploration well commitment under the PSC, is approved by the commitment. As at year end, it is not probable that this contingent
relevant government entity. consideration trigger will be met.
10. The plan of development described in item 9 above is approved by the relevant US$8.0 million There are no prospects or leads presently selected for the exploration well
government entity and is based on reserves of no less than 8.4mm barrels (on a commitment. As at year end, it is not probable that this contingent
gross basis). consideration trigger will be met.
((c) ) Included in the provision for employee benefits is provision
for long service leave which is payable to employees on a pro-rata basis after
7 years of employment and is due in full after 10 years of employment.
((d) ) The reclassification related to the abandonment payment made
from the CWLH Assets trust fund, following the operator's statement which was
recorded under asset retirement obligations.
((e) ) US$1.1 million credited to profit or loss due to a change in
underlying assumptions for provisions for manpower related at Montara.
((f) ) In 2024, the Group provided US$10.0 million toward an
exploration commitment well for the Nam Du field development located in Block
46/07. The well has been incorporated into the field development plan ("FDP")
for the gas facility, which management has received approval from Vietnamese
regulatory authorities in March 2026 as disclosed in Note 46.
((g) ) US$3.7 million of other provision in 2025 relating to the
interest on tax following Australia tax ruling in respect of prior year tax
claims relating to the H6 well drilled for Montara.
37. Borrowings
2025 2024
US$'000 US$'000
Non-current secured borrowings
Reserve based lending facility 40,288 122,978
Current secured borrowings
Reserve based lending facility 111,093 77,212
151,381 200,190
On 19 May 2023, the Group signed a US$200.0 million RBL facility with a Group
of four international banks, with a fifth bank entering on 15 November 2023.
The facility tenor is four years, with the final maturity date being the
earlier of 31 March 2027 and the projected reserves tail 53 (#_ftn53) (which
is expected later).
The borrowing base 54 (#_ftn54) was initially secured over the Group's main
producing assets being Montara, Stag, CWLH, Sinphuhorm Assets, the PenMal
Assets' PM323 and PM329 PSCs and the Group's development asset being the
Lemang PSC. At the March 2024 redetermination, Stag was removed from the
borrowing base and replaced with a second tranche of CWLH acquisition which
completed in February 2024 as disclosed in Note 19. Notwithstanding the
removal of Stag from the borrowing base for the purpose of calculating the
borrowing base amount, Jadestone Energy (Australia) Pty Ltd, as Stag
titleholder, remains an Obligor under the RBL facility such that security in
favor of the lenders over Stag titles, bank accounts and insurance remains in
place and the information undertakings and restrictions on cash movement to
entities outside RBL continue to apply. Following the sale and purchase
agreement to sell Jadestone Energy (Thailand) Pte Ltd and its interest in the
Sinphuhorm gas fields as further disclosed in Note 24, Sinphuhorm asset was
removed from the borrowing base.
The maximum facility limit is at US$200.0 million. The borrowing base was
US$167.0 million in the first quarter of 2025 and was subsequently reduced to
US$150.0 million for the remainder of the year (2024: US$200 million).
Under the RBL facility the Group pays interest at 450 basis points over the
secured overnight financing rate ("SOFR"), plus the applicable credit spread
which is between 0.11% to 0.45% depending on the duration of the relevant
interest period. The Group also pays customary arrangement and commitment
fees.
As at 31 December 2025, the Group had incurred total interest expenses of
US$18.9 million (2024: US$21.5 million, net interest of US$16.4 million) and
no commitment fees in 2025 (2024: US$0.1 million) has been recognized as
disclosed in Note 15. In 2024, US$5.1 million has been capitalized as
disclosed in Note 21. The capitalization rate used to determine the amount of
borrowing costs eligible for capitalization was 9.26% in 2024.
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 on drawn amount and 4% on undrawn amount. In 2024, the Group
incurred interest of US$0.9 million. The facility was undrawn as of 31
December 2025. The facility, if required, may be drawn upon to support general
corporate purposed.
The secured borrowing is subject to a financial covenant which is tested
semi-annually on 30 June and 31 December each year. The covenant measures the
Group's gearing ratio as calculated in Note 43. The carrying amount of the
secured borrowings subject to the covenant was US$151.4 million as at 31
December 2025.
The Group complied with the covenant requirements during the years ended 31
December 2025 and 2024. As at the reporting date, the Directors are not aware
of any facts or circumstances that would indicate that the Group may have
difficulty complying with the covenant requirements within twelve months after
the reporting period.
38. Lease liabilities
2025 2024
US$'000 US$'000
Presented as:
Non-current 33,586 3,4861
Current 8,351 14,065 55 (#_ftn55)
41,937 17,551
Maturity analysis of lease liabilities based on undiscounted gross cash flows:
Year 1 12,083 15,083
Year 2 10,012 3,571
Year 3 10,065 -
Year 4 9,892 -
Year 5 9,630 -
Year 6 1,380 -
Future interest charge (11,125) (1,103)
41,937 17,551
The Group does not face a significant liquidity risk with regards to its lease
liabilities. Lease liabilities are monitored within the Group's treasury
function.
39. Reconciliation of liabilities arising from financing activities
The table below details changes in the Group's liabilities arising from
financing activities, including both cash and non-cash changes. Liabilities
arising from financing activities are those for which cash flows were, or
future cash flows will be, classified in the Group's consolidated statement of
cash flows, as cash flows from financing activities.
The cash flows represent the repayment of borrowings and lease liabilities, in
the consolidated statement of cash flows.
Lease liabilities
Borrowings US$'000
US$'000
As at 1 January 2024 154,573 32,864
Repayment of lease liabilities - (18,985)
Total drawdown of borrowings 43,000 -
New lease liabilities - 1,207
Interest on borrowings paid (18,944) -
Commitment fees of borrowings paid (142)
RBL commitment fees 142
Non-cash changes - interest 16,428 2,465
Capitalization of borrowing costs (Note 21) 5,133 -
As at 31 December 2024 and 1 January 2025 200,190 17,551
Repayment of lease liabilities - (16,206)
Repayment of borrowings (50,000) -
New lease liabilities - 39,511
Interest on borrowings paid (17,737) -
Non-cash changes - interest 18,928 1,081
As at 31 December 2025 151,381 41,937
40. Trade and other payables
2025 2024
US$'000 US$'000
Current
Trade payables 9,071 26,520
Other payables 13,229 12,809
Accruals 47,534 51,805
Malaysian supplementary payment payables 146 392
Amount due to joint arrangement partner 2,346 1,082
GST/VAT payables 134 185
72,460 92,793
Non-current
Other payable 20,413 16,917
Accrual 290 365
20,703 17,282
93,163 110,075
Trade payables, other payables and accruals principally comprise amounts
outstanding for trade and non-trade related purchases and ongoing costs. The
average credit period taken for purchases is 30 days (2024: 30 days). For most
suppliers, no interest is charged on the payables in the first 30 days from
the date of invoice. Thereafter, interest may be charged on outstanding
balances at varying rates of interest. The Group has financial risk management
policies in place to ensure that all payables are settled within the
pre-agreed credit terms.
The non-current other payable represents amounts received in advance from the
Malaysian joint arrangement partner in respect of its share of future well
preservation activities, pipeline replacement and decommissioning costs
relating to the PNLP Assets, following its withdrawal from the licenses in
2023. The amounts will be utilized to fund the Group's future obligations for
these activities.
The non-current accrual represents the DCP plan granted in 2023 and 2024 as
disclosed in Note 33. The DCP has a three-year vesting period, during which
certain pre-conditions must be met. The vesting period also represents the
assessment period for determining whether the pre-conditions are satisfied.
Upon vesting, the DCP will be settled in cash at varying payout rates subject
to the Group's performance. The performance measures for the DCP are
consistent with those applied to the performance shares as disclosed in Note
33.2. The DCP is measured at fair value as at 31 December 2025.
As at 31 December 2025, the total DCP recognized amounted to US$0.6 million,
of which US$0.3 million is classified as current.
41. Derivative financial instruments
2025 2024
US$'000 US$'000
Derivative financial assets
Designated as cash flow hedges
Commodity swap 9,331 -
9,331 -
Analyzed as:
Current 9,331 -
Non-current - -
9,331 -
Derivative financial liabilities
Designated as cash flow hedges
Commodity swap - 7,618
- 7,618
Analyzed as:
Current - 7,618
Non-current - -
- 7,618
The following is a summary of the Group's outstanding derivative contracts:
Fair value asset/ Fair value asset/
(liability) (liability)
at 31 December at 31 December
Contract quantity Type of contracts Hedge classification 2025 2024
Term Contract price US$'000 US$'000
Contracts designated as cash flow hedges
20% to
70% of Weighted average price of US$ 69.18/bbl
Group's Jan
planned Commodity swap: swap component((a)) 2026 -
2P Sep
production 2026((b)) Cash flow 9,331 (7,618)
((a)) Swap component referring to hedge sales and the price of the commodity.
((b)) On 20 June 2025, the Group entered into additional commodity swaps
contracts, extending the terms from September 2025 to September 2026.
The Group's commodity swap programme was designated as a cash flow hedge.
Critical terms of the commodity swap (i.e., the notional amount, life and
underlying oil price benchmark) and the corresponding Group's hedged sales are
highly similar. The Group performed a qualitative assessment of the
effectiveness of the commodity swap contracts and concluded that the commodity
swap programme is highly effective as the value of the commodity swap and the
value of the corresponding hedged items will systematically change in opposite
directions in response to movements in the underlying commodity prices.
The following tables detail the commodity swap contracts outstanding at the
end of the year, as well as information regarding their related hedged items.
Commodity swap contract assets are included in the "derivative financial
instruments" line item in the consolidated statement of financial position.
Hedging instruments - outstanding contracts
Change in fair value used for calculating hedge ineffectiveness
US$'000
Fair value asset/ (liability)
Notional value US$'000
Oil volumes US$'000
bbls
2024
Cash flow hedges
Commodity swap component 1,733,020 119,698 - (7,618)
2025
Cash flow hedges
Commodity swap component 1,083,997 74,991 - 9,331
( )
The following table details the effectiveness of the hedging relationships and
the amounts reclassified from hedging reserve to profit or loss:
Current period hedging gain/(loss) recognized in OCI Amount of hedge ineffectiveness recognized in profit or loss Line item in profit or loss in which hedge ineffectiveness is included Amount reclassified to profit or loss due to hedged item affecting profit or Line item in profit or loss in which reclassification adjustment is included
loss
US$'000 US$'000
US$'000
2024
Cash flow hedges
Forecast sales (7,618) - Other income (27,417) Revenue
2025
Cash flow hedges
Forecast sales 9,331 (303) Other income 2,220 Revenue
42. 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 at 31 December 2025, the fair value of warrant liability
was US$0.03 million (2024: US$0.9 million). The movement in the fair value of
warrants liability of US$0.9 million is disclosed in Note 16.
The Directors have applied the Black-Scholes option-pricing model, with the
following assumptions, to estimate the fair value of the warrants as at
year-end:
2025 2024
Risk-free rate 3.8% 4.48%
Expected life 0.4 years 1.4 years
Expected volatility 56 (#_ftn56) 40.44% 59.5%
Share price GB£ 0.24 GB£ 0.24
Exercise price GB£ 0.50 GB£ 0.50
Expected dividends 0% 0%
43. Financial instrument, financial risks and capital management
Financial assets and liabilities
Current assets and liabilities
The Directors consider that due to the short-term nature of the Group's
current assets and liabilities, the carrying amounts equate to their fair
value.
Non-current assets and liabilities
The carrying amount of non-current assets and liabilities approximates their
fair values. For financial instruments measured at amortized cost, fair value
is estimated by discounting expected future cash flows using market-based
discount rates for similar instruments. The Group considers that any
difference between carrying amounts and fair values is not material.
2025 2024
US$'000 US$'000
Financial assets
At amortized cost
Trade and other receivables, excluding prepayments, GST/VAT 302,392 287,027
receivables and underlift crude oil inventories
Cash and bank balances 60,916 95,226
Derivative financial instruments designated as cash flow hedges 9,331 -
372,639 382,253
Financial liabilities
At amortized cost
Trade and other payables, excluding contingent payments, GST/VAT payables 93,029 109,890
and overlift crude oil inventories
Lease liabilities 41,937 17,551
Borrowings 151,381 200,190
Contingent consideration for Lemang PSC acquisition 700 700
Derivative financial instruments designated as cash flow hedges - 7,618
287,047 335,949
Fair values are based on the Directors' best estimates, after consideration of
current market conditions. The estimates are subjective and involve
judgment, and as such may deviate from the amounts that the Group realizes in
actual market transactions.
Commodity price risk
The Group's earnings are affected by changes in oil prices. As part of the
RBL, the Group entered into commodity swap contracts to hedge 20% to 70% of
its forecasted production under the RBL (Note 41).
Commodity price sensitivity
The results of operations and cash flows from oil and gas production can vary
significantly with fluctuations in the market prices of oil and/or natural
gas. These are affected by factors outside the Group's control, including
the market forces of supply and demand, regulatory and political actions of
governments, and attempts of international cartels to control or influence
prices, among a range of other factors.
The table below summarizes the impact on (loss)/profit before tax, and on
equity, from changes in commodity prices on the fair value of derivative
financial instruments. The analysis is based on the assumption that the
crude oil price moves 10%, with all other variables held constant. The Group
considers a 10% movement in crude oil prices to remain a reasonably possible
change for the purpose of sensitivity analysis. This assessment is based on
observed historical price volatility, prevailing geopolitical and
supply-related uncertainties in the oil market, and external market forecasts
as at the reporting date. The Directors are of the view that this assumption
continues to appropriately reflect potential short-term fluctuations in crude
oil prices.
Effect on other Effect on other
Effect on the comprehensive Effect on the comprehensive
result income before tax result income before tax
before tax for the for the year ended before tax for the for the year ended
year ended 31 December 2025 year ended 31 December 2024
Gain or loss 31 December 2025 US$'000 31 December 2024 US$'000
US$'000 US$'000
Increase by 10% Not applicable (6,566) Not applicable (12,732)
Decrease by 10% Not applicable 6,566 Not applicable 12,732
Foreign currency risk
Foreign currency risk is the risk that a variation in exchange rates between
United States Dollars ("US Dollar") and foreign currencies will affect the
fair value or future cash flows of the Group's financial assets or liabilities
presented in the consolidated statement of financial position as at year
end.
Cash and bank balances are generally held in the currency of likely future
expenditures to minimize the impact of currency fluctuations. It is the
Group's normal practice to hold the majority of funds in US Dollars, in order
to match the Group's revenue and expenditures.
In addition to US Dollar, the Group transacts in various currencies, including
Australian Dollar, Malaysian Ringgit, Vietnamese Dong, Indonesian Rupiah,
Singapore Dollar and British Pound Sterling.
The Group manages its foreign currency risk by monitoring the fluctuations of
material foreign currencies against US$ and potentially entering into foreign
currency forward contract to hedge against the currency fluctuations if and
when considered appropriate.
Foreign currency sensitivity
Material foreign denominated balances were as follows:
2025 2024
Cash and bank balances
Australian Dollars 2,945 1,894
Malaysian Ringgit 5,972 4,820
Indonesian Rupiah 974 379
Trade and other receivables
Australian Dollars 556 21,826
Malaysian Ringgit 90,530 92,240
Indonesian Rupiah 1,270 944
Trade and other payables
Australian Dollars 7,131 41,676
Malaysian Ringgit 21,905 42,027
Indonesian Rupiah 744 1,405
A strengthening/weakening of the Australian dollar, Malaysian Ringgit and
Indonesian Rupiah by 10%, against the functional currency of the Group, is
estimated to result in the net carrying amount of Group's financial assets and
financial liabilities as at year end decreasing/increasing by approximately
US$6.6 million (2024: US$3.5 million), and which would be charged/credited to
the consolidated statement of profit or loss.
Interest rate risk
The Group's interest rate exposure arises from its cash and bank balances,
CWLH Assets abandonment trust fund and borrowings. The Group's other financial
instruments are non-interest bearing or fixed rate, and are therefore not
subject to interest rate risk. The Group continually monitors its cash
position and places excess funds into fixed term deposits as necessary.
As at 31 December 2025, the Group held US$168.1 million (2024: US$165.8
million) in the CWLH Assets abandonment trust fund operated by the joint
venture operating partner. The abandonment trust fund generates average annual
interest rate of 2.37% (2024: 3.16%).
As at 31 December 2025, the Group has a net drawdown sum of US$150.0 million
(2024: US$200.0 million). The loan incurred costs of US$7.0 million in 2023.
The RBL facility pays interest at 450 basis points over the secured overnight
financing rate, plus the applicable credit spread which is between 0.11% to
0.45% depending on the duration of the relevant interest period. The Group
also pays customary arrangement and commitment fees.
Based on the carrying value of the CWLH Assets abandonment trust fund, fixed
term deposits and RBL as at 31 December 2025, if interest rates had
increased/decreased by 1% and all other variables remained constant, the
Group's net loss before tax would be increased/decreased by US$0.1 million
(2024: net loss before tax would be increased/decreased by US$0.1 million).
Credit risk
Credit risk represents the financial loss that the Group would suffer if a
counterparty in a transaction fails to meet its obligations in accordance with
the agreed terms.
The Group actively manages its exposure to credit risk, granting credit limits
consistent with the financial strength of the Group's counterparties and
respective sole customer in Australia for oil sales, Malaysia for both oil and
gas sales and Indonesia for gas sales. In addition to there are several
customers for LPG and condensate sales in Indonesia requiring financial
assurances as deemed necessary, reducing the amount and duration of credit
exposures, and close monitoring of relevant accounts.
The Group trades only with recognized, creditworthy third parties.
The Group's current credit risk grading framework comprises the following
categories:
Category Description Basis for recognizing expected credit losses ("ECL")
Performing The counterparty has a low risk of default and does not have any past due 12-month ECL 57 (#_ftn57)
amounts.
Doubtful Amount is > 30 days past due indicating significant increase in credit risk Lifetime ECL - not credit-impaired
since initial recognition
In default Amount is > 90 days past due is evidence indicating the assets is Lifetime ECL - credit-impaired
credit-impaired.
Write-off There is evidence indicating that the debtor is in severe financial difficulty Amount is written off
and the Group has no realistic prospect of recovery.
The table below details the credit quality of the Group's financial assets and
other items, as well as maximum exposure to credit risk by credit risk rating
grades:
External credit Internal credit 12-month ("12m") or Gross carrying amount ((i)) Loss Net carrying amount
lifetime allowance
Notes rating rating ECL US$'000 US$'000 US$'000
2025
Trade 28 A2 (i) Lifetime ECL 30,523 -* 30,523
receivables
Other 28 n.a (i) 12m ECL 7,764 -* 12,099
receivables
Amount due 28 n.a (i) 12m ECL 1,807 -* 1,807
from joint
arrangement
partners
Non-current 28 n.a (i) 12m ECL 94,807 -* 258,525
other
receivables
Cash and bank n.a 60,916 -* 60,916
balances 30 Performing 12m ECL
2024
Trade 28 A2 (i) Lifetime ECL 15,846 -* 15,846
receivables
Other 28 n.a (i) 12m ECL 3,622 -* 7,731
receivables
Amount due 28 n.a (i) 12m ECL 2,390 -* 2,390
from joint
arrangement
partners
Non-current 28 n.a (i) 12m ECL 92,551 -* 261,517
other
receivables
Cash and bank n.a 95,226 -* 95,226
balances 30 Performing 12m ECL
* The amount is negligible.
(i) For trade receivables, the Group has applied the simplified approach in
IFRS 9 to measure the loss allowance at lifetime ECL. The Group determines the
expected credit losses on these items by using specific identification,
estimated based on historical credit loss experience based on the past due
status of the debtors, adjusted as appropriate to reflect current conditions
and estimates of future economic conditions. As at year end, ECL from trade
receivables are expected to be insignificant.
As at 31 December 2025, total trade receivables amounted to US$30.5 million
(2024: US$15.8 million). The balance in 2025 and 2024 had fully recovered in
2026 and 2025, respectively, except for US$0.6 million (2024: US$0.5 million)
allowance for expected credit loss has been recognized due to bad debts.
The concentration of credit risk 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 and a different single customer for gas in Indonesia. All
customers have an A2 credit rating (Moody's). All trade receivables are
generally settled 30 days after sale date. In the event that an invoice is
issued on a provisional basis, the final reconciliation is paid within 3 to 14
days from the issuance of the final invoice, largely mitigating any credit
risk.
The Group measures the loss allowance for other receivables and amount due
from joint arrangement partners at an amount equal to 12-months ECL, as there
is no significant increase in credit risk since initial recognition. ECL for
other receivables are expected to be insignificant.
The credit risk on cash and bank balances and CWLH trust fund is limited
because counterparties are banks with high credit ratings assigned by
international credit rating agencies.
The maximum credit risk exposure relating to financial assets is represented
by their carrying value as at the reporting date.
Liquidity risk
Liquidity risk is the risk that the Group will not be able to meet all of its
financial obligations as they become due. This includes the risk that the
Group cannot generate sufficient cash flow from producing assets, or is unable
to raise further capital in order to meet its obligations.
The Group manages its liquidity risk by optimising the positive free cash flow
from its producing assets, on-going cost reduction initiatives, merger and
acquisition strategies, bank balances on hand and in case appropriate,
lending.
The Group's net loss after tax for the year was US$110.7 million (2024:
US$44.1 million). Operating cash flows before movements in working capital and
net cash generated in operating activities for the year ended 31 December 2025
was US$123.6 million and US$91.4 million (2024: US$70.5 million and net cash
used in US$30.7 million) respectively. The Group's net current liabilities is
US$13.0 million as at 31 December 2025 (2024: net current assets of US$9.2
million).
At 31 December 2025 the Group's total liabilities exceeded its total assets.
The refinancing of the balance sheet following the US$200 million bond in
March 2026 will reclassify borrowings of US$111.1 million at year end, to
non‑current liabilities, reflecting the five year tenor of the bond,
amortizing after year three. The majority of the Group's non-current
liabilities are related to the Group's asset retirement obligations which do
not fall due earlier than five to ten years in the future and therefore do not
impact short-term liquidity.
The Group is required to maintain a parent company financial covenant as
disclosed in Note 37 of consolidated net debt below 3.5x annual EBITDAX and to
deliver the required information to the RBL Banks on a timely basis as
disclosed in Note 37. As at 31 December 2025, the Company's financial covenant
was 0.77 (2024: 1.20).
Further details are disclosed in the Going Concern section in Note 3.
Derivative and non-derivative financial liabilities
The following table details the expected contractual maturity for derivative
and non-derivative financial liabilities with agreed repayment periods. The
table below is based on the undiscounted contractual maturities of the
financial liabilities, including interest, that will be paid on those
liabilities, except where the Group anticipates that the cash flow will occur
in a different period.
Weighted average effective On demand or within Within 2 to 5 More than
interest rate 1 year years 5 years Total
% US$'000 US$'000 US$'000 US$'000
2025
Non-interest bearing
Trade and other payables, excluding contingent payments, GST/VAT payables and - 72,326 20,703 - 93,029
overlift crude oil inventories
Contingent consideration for Lemang PSC acquisition - 700 - - 700
Fixed interest rate instrument
Lease liabilities 4.888 12,083 40,979 - 53,062
Variable interest rate instrument
Borrowings 12.871 111,093 40,288 - 151,381
196,202 101,970 - 298,172
2024
Non-interest bearing
Trade and other payables, excluding contingent payments, GST/VAT - 92,608 17,282 - 109,890
payables and overlift crude oil inventories
Contingent consideration for Lemang PSC acquisition - 700 - - 700
Derivatives financial instruments designated as cash flow hedges - 7,618 - - 7,618
Fixed interest rate instrument
Lease liabilities 9.778 15,083 3,571 - 18,654
Variable interest rate instrument
Borrowings 12.789 77,212 122,978 - 200,190
193,221 143,831 - 337,052
Non-derivative financial assets
The following table details the expected maturity for non-derivative financial
assets. The inclusion of information on non-derivative financial assets
assists in understanding the Group's liquidity position and phasing of net
assets and liabilities, as the Group's liquidity risk is managed on a net
asset and liability basis. The table is based on the undiscounted contractual
maturities of the financial assets, including interest that will be earned on
those assets, except where the Group anticipates that the cash flow will occur
in a different period.
Weighted average On Demand Within More
effective or within 2 to 5 than
interest rate 1 year years Total
5 years
% US$'000 US$'000 US$'000 US$'000
2025
Non-interest bearing
Trade and other receivables, excluding prepayments, GST/VAT receivables and - 43,867 121,707 136,818 302,392
underlift crude oil inventories((a))
Derivative financial instruments designated as cash flow hedges - 9,331 - - 9,331
Variable interest rate instruments
Cash and bank balances -((b)) 60,606 310 - 60,916
113,804 122,017 136,818 372,639
2024
Non-interest bearing
Trade and other receivables, excluding prepayments, GST/VAT receivables and - 25,510 102,692 158,825 287,027
underlift crude oil inventories((a))
Variable interest rate instruments
Cash and bank balances -((b)) 94,338 888 - 95,226
119,848 103,580 158,825 382,253
( )
((a)) There is US$3.8 million (2024: US$4.4 million) of abandonment trust
funds interest that are interest bearing with a weighted average effective
interest rate of 2.37% (2024: 3.16%).
((b)) The effect of interest is not material.
Capital management
The Group manages its capital structure and makes adjustments to it, based on
funding requirements of the Group combined with sources of funding available
to the Group, in order to support the acquisition, exploration and development
of resource properties and the ongoing (investment in) operations of its
producing assets. Given the nature of the Group's activities, the Board of
Directors works with management to ensure that capital is managed effectively,
and the business has a sustainable future.
The capital structure of the Group represents the equity of the Group,
comprising share capital, merger reserve, share-based payment reserve, capital
redemption reserve and hedging reserve, as disclosed in Notes 30, 32, 33, 34
and 35, respectively.
To carry-out planned asset acquisitions, exploration and development, and to
pay for administrative costs, the Group may utilize excess cash generated from
its ongoing operations and may utilize its existing working capital, position
and will work to raise additional debt and/or equity funding should that be
necessary.
The Directors regularly review the Group's capital management strategy and
consider the current approach appropriate, given the Group's relative size.
The decline in the Net Debt to Equity ratio during the year primarily driven
by reduction in net debt from lower borrowing as well as a significant change
in Group's equity position during the year.
2025 2024
US$'000 US$'000
Gearing ratio
Borrowings 58 (#_ftn58) 151,381 200,190
Cash and cash equivalents (60,916) (95,226)
Net debt 90,465 104,964
Equity (78,949) 18,834
Net debt to equity ratio (1.15) 5.57
The Group's overall strategy towards the capital structure remains unchanged
as management anticipate the new investment will support debt reduction and
improved equity in the future.
Fair value measurements
The Group discloses fair value measurements by level of the following fair
value measurement hierarchy:
i. Quoted prices (unadjusted) in active markets for identical assets or
liabilities (Level 1);
ii. Inputs, other than quoted prices included within Level 1, that are
observable for the asset or liability, either directly or indirectly (Level
2); and
iii. Inputs for the asset or liability that are
not based on observable market data (unobservable inputs) (Level 3).
Fair value (US$'000) as at Valuation Relationship of
Financial assets/financial 2025 2024 Fair value technique(s) Significant unobservable inputs
liabilities Assets Liabilities Assets Liabilities hierarchy and key input(s) unobservable input(s) to fair value
Derivative financial instruments
1) Commodity swap 9,331 - - 7,618 Level 2 Third-party valuations based on market comparable information. - -
contracts (Note 41)
Others - contingent consideration from Lemang PSC acquisition
2) Contingent consideration (Note 36) - 700 - 700 Levels 1 and 3 Based on the nature and the likelihood of the occurrence of the trigger - -
events. Fair value is estimated, taking into consideration the estimated
future gas production schedule, forecasted Dated Brent oil prices of
US$62.86/bbl and Saudi CP prices of US$490.61/MT in the second year of
production, estimated future recoverability of VAT receivables as well as the
effect of the time value of money.
44. Segment information
Information reported to the Group's Chief Executive Officer (the chief
operating decision maker) for the purposes of resource allocation is focused
on two reportable/business segments driven by different types of activities
within the upstream oil and gas value chain, namely producing assets and
secondly development and exploration assets. The geographic focus of the
business is on Australia, Malaysia, Indonesia, and Vietnam.
Revenue and non-current assets information based on the geographical location
of assets respectively are as follows:
Producing assets Exploration/development
Australia Malaysia Indonesia Thailand ((a)) Vietnam Corporate Total
US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000
2025
Revenue
Liquids revenue 276,964 40,153 15,373 - - - 332,490
Gas revenue - 635 74,935 - - - 75,570
276,964 40,788 90,308 - - - 408,060
Production cost (185,449) (26,093) (21,118) - - - (232,660)
Depletion, depreciation and amortization (74,876)
(7,156) (17,205) - (57) (251) (99,545)
Administrative staff costs (5,124) (2,412) (1,757) - (1,296) (13,192) (23,781)
Other expenses (39,361) (3,982) (5,161) (30) (495) (640) (49,669)
Allowance for expected credit losses - - (105) - - - (105)
Impairment of assets (126,040) - - - - - (126,040)
Share of results of associate accounted for using the equity method - - - 1,849 - - 1,849
Other income 15,184 7,006 105 2,276 17 15,561 40,149
Finance costs (24,734) (7,733) 536 - (6) (20,922) (52,859)
Other financial gains - - - - - 928 928
(Loss)/Profit before tax (163,436) 418 45,603 4,095 (1,837) (18,516) (133,673)
(Reductions)/additions to non-current assets (63,626) 4,631 5,662 - 2,285 136 (50,912)
Non-current assets((b)) 181,916 289,179 167,183 - 86,277 409 724,964
(a)) This represents the income statement figures for Thailand up until
disposal date of 16 April 2025.
((b)) The non-current assets in the segmental note exclude deferred tax assets
from the consolidated statement of financial position
Producing assets Exploration/development
Australia Malaysia Indonesia Thailand Vietnam Indonesia Corporate Total
US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000
2024
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 (228,091) (46,969) (11,848) - - - - (286,908) 59 (#_ftn59)
Depletion, depreciation and amortization (77,297)
(10,956) (2,809) - (89) - (256) (91,407)1
Administrative staff costs (8,957) (1,735) (393) - (1,162) (535) (11,824) (24,606)1
Other expenses (8,827) (4,693) (2,763) (1,623) (463) (624) (4,744) (23,737)
Allowance for expected credit losses - - (457) - - - - (457)
Share of results of associate accounted for using the equity method - - - 1,553 - - - 1,553
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- 103,022 43,000 535 - 11,837 42,309 - 200,703
current assets
Non-current assets((a)) 262,784 289,530 178,501 19,544 84,056 - 405 834,820
((a))The non-current assets in the segmental note exclude deferred tax assets
from the consolidated statement of financial position
Revenue arising from producing assets relates to the Group's single customer
with respect to oil sales in Australia, different single customers 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 so they can be sold to other buyers,
if required.
45. Financial capital commitments
Certain PSCs and service concessions have firm capital commitments. The
Group has the following outstanding minimum commitments:
PSC operational commitments
2025 2024
US$'000 US$'000
Not later than one year 2,450 460
One to five years 4,828 9,404
More than 5 years 1,400 1,978
8,678 11,842
The PSC operational commitment as at 31 December 2025 amounted to US$4.6
million (2024: US$7.3 million) relates to the Lemang PSC. The operational
commitments also include training commitment of US$4.1 million (2024: US$4.7
million), for the Block 46/07 PSC, Block 51 PSC and the PenMal Assets.
Work commitment
As part of the acquisition under the terms of the Lemang PSC, the Group, as
the operator, has inherited unfulfilled work commitments of US$4.5 million
(2024: US$7.3 million) consisting of one exploration well and a 3D seismic
programme.
Training commitment
Under the terms of the Block 46/07 PSC and Block 51 PSC, the Group commits to
pay an annual training commitment amount of US$3.8 million to Petrovietnam
until the expiration of the respective PSC license. The training commitment
amount is for the purpose of developing the local employees in the oil and gas
industry.
As part of the acquisition under the terms of the PenMal Assets, the Group has
inherited net training commitments of US$0.3 million (2024: US$0.3 million)
and US$0.1 million (2024: US$0.1 million) for PM323 PSC and PM428
respectively. Funds provided with respect to this training commitment are
applied to the development of local employees in the oil and gas industry. The
training commitments are required to be completed before the expiration of the
respective PSC.
Capital commitments
The Group has the following capital commitments for expenditures that were
contracted for at the end of the reporting year but not recognized as
liabilities:
2025 2024
US$'000 US$'000
Not later than one year 4,009 13,611
One to five years 218 2,652
4,227 16,263
The capital commitments of US$1.4 million as at 2025 year end predominately
arose from the Lemang PSC's engineering, procurement, construction and
installation ("EPCI") contract awarded to design and build the gas processing
facility. The capital commitments comprise a series of enhancement initiatives
identified during the start-up and early operational phase of Akatara Gas
Processing Facility.
The Group also contracted for US$2.7 million for capital expenditure
replacement in Montara and US$0.1 million which is associated with Stag
capital expenditure.
46. Events after the end of the reporting period.
Vietnam Field Development Plan ("FDP") approval
On 18 March 2026, the Group received approval for the Field Development Plan
("FDP") for the Nam Du / U Minh gas fields in Vietnam. The approval represents
a key milestone in progressing the development of the project and enables the
recognition of initial proved and probable ("2P") reserves of approximately 32
MMboe. The Group is also advancing discussions with potential farm-in partners
and progressing towards the development phase of the project.
Placement of Nordic bond issue
On 26 March 2026, the Group successfully completed a US$200.0 million senior
secured bond issue with a maturity in 2031 and a coupon of 12%. The bond
principal amortizes at US$50 million per annum commencing from the third
anniversary of the bond issue, with a final repayment of US$100 million at
maturity.
PM329 PSC
On 10 September 2025, the joint venture partner issued a withdrawal notice
from PM329, effective 1 January 2026. As a result, Jadestone assumed a 100%
participating interest in the PSC.
Stag field update
On 23 March 2026, the Group temporarily shut down and demobilized the Stag
offshore platform in advance of Cyclone Narelle, which escalated into a
Category 5 storm. Upon re-manning on 28 March 2026, storm-related damage was
found to have affected the platform and its offloading facilities. The Group
is currently assessing the extent of the damage and developing a repair plan
to restore production operations. Physical damage and business interruption
insurance coverage is in place, and the incident is not anticipated to have a
material financial impact on the Group
47. RELATED PARTY TRANSACTIONS
Compensation of key management personnel
2025 2024
US$'000 US$'000
Short-term benefits (Note 10) 4,250 2,526
Other benefits (Note 10) 180 181
Share-based payments (Note 10) 521 233
Compensation for loss of office - 2,464
4,951 5,404
The total remuneration of key management members (including salaries and
benefits) was US$5.6 million (2024: US$5.4 million) and recognized as part of
the Group's administrative staff costs as disclosed in Note 8.
Compensation of Directors
Share-based payments
Short-term benefits((a)) Other benefits((a)) Total compensation
US$'000 US$'000 US$'000 US$'000
2025
Cedric Fontenit ((b)) 13 - - 13
David Neuhauser 80 - - 80
Jenifer Thien((b)) 52 - - 52
Joanne Williams 705 - - 705
Adel Chaouch 1,324 50 438 1,812
Andrew Fairclough 1,033 41 33 1,107
Linda Beal 125 5 - 130
Gunter Waldner((c)) - - - -
Thomas Mitchell Little((b)) 878 79 50 1,007
David Mendelson((b)) 117 5 - 122
4,327 180 521 5,028
Share-based payments
Short-term benefits((a)) Other benefits((a)) Total compensation
US$'000 US$'000 US$'000 US$'000
2024
A. Paul Blakeley((d)) 908 2,543 90 3,541
Bert-Jaap Dijkstra((d)) 757 92 132 981
Dennis McShane((d)) 39 - - 39
Iain McLaren((d)) 48 - - 48
Robert Lambert((d)) 24 - - 24
Cedric Fontenit 89 - - 89
Lisa Stewart((d)) 25 - - 25
David Neuhauser 80 - - 80
Jenifer Thien 100 - - 100
Joanne Williams((d)) 89 - 8 97
Adel Chaouch((d)) 157 - - 157
Andrew Fairclough((d)) 141 10 3 154
Linda Beal((d)) 69 3 - 72
Gunter Waldner((c)) - - - -
2,526 2,648 233 5,407
((a)) Short-term benefits comprise salary, Director fee as applicable,
performance pay, pension and other allowances. Other benefits comprise
benefits-in-kind, including employer National Insurance (NI) contributions
borne by the Group. Other benefits also include compensation for loss of
office amounting to US$2.3 million, including US$0.2 million of payroll tax
for A. Paul Blakeley.
((b)) During the year, Cedric Fontenit and Jenifer Thien stepped down as the
Directors. Thomas Mitchell Little and David Mendelson were appointed during
the year.
((c)) Mr. Waldner was appointed as the Non-Executive Director of the Company
as a direct obligation under a 2018 Relationship Agreement between Tyrus and
the Company. Both parties agreed that Mr. Waldner will not receive Director
fee but is reimbursable for reasonable and documented expenses incurred in
performing the Non-Executive Director duties.
((d)) In 2024, A.Paul Blakeley, Bert-Jaap Dijkstra, Dennis McShane, Iain
Mclaren, Robert Lambert and Lisa Stewart stepped down as the Directors. Joanne
Williams, Adel Chaouch, Andrew Fairclough and Linda Beal were appointed.
Company Statement of Financial Positio as at 31 December 2025
2025 2024
Notes US$'000 US$'000
Assets
Non-current assets
Investment in subsidiaries 5 29,317 28,005
Loan to a subsidiary 7 235,451 214,579
Total non-current asset 264,768 242,584
Current assets
Amount owing by subsidiaries 7 120,668 128,776
Prepayments 48 30
Cash and cash equivalents 3,469 979
Total current assets 124,185 129,785
Total assets 388,953 372,369
Equity and liabilities
Equity
Capital and reserves
Share capital 8 458 457
Share premium account 8 52,505 52,176
Merger reserve 10 61,068 61,068
Share-based payment reserve 11 28,712 27,730
Capital redemption reserve 24 24
Retained earnings 244,136 228,575
Total equity 386,903 370,030
Company Statement of Financial Position as at 31 December 2025 (cont'd)
2025 2024
Notes US$'000 US$'000
Liabilities
Current liabilities
Other payables and accruals 12 2,047 1,408
Warrant liability 13 3 931
Total current liabilities 2,050 2,339
Total liabilities 2,050 2,339
Total equity and liabilities 388,953 372,369
During the year, the Company made a profit after tax of US$15.6 million (2024:
loss after tax of US$7.3 million).
Company Statement of Changes in Equity for the year ended 31 December 2025
Share premium Capital redemption reserve Share-based payments reserve
Share capital account US$'000 US$'000 Merger reserve Retained earnings
US$'000 US$'000 US$'000 US$'000 Total
US$'000
As at 1 January 2024 456 51,827 24 27,673 61,068 235,842 376,890
Share-based compensation:
Subsidiaries - - - 407 - - 407
Shares issued (Note 8) 1 349 - (350) - - -
Total transactions with owners 457 52,176 24 27,730 61,068 235,842 377,297
Loss and total comprehensive income for the year - - - - - (7,267) (7,267)
As at 31 December 2024 and 1 January 2025 457 52,176 24 27,730 61,068 228,575 370,030
Share-based compensation:
Subsidiaries - - - 1,312 - - 1,312
Shares issued (Note 8) 1 329 - (330) - - -
Total transactions with owners 458 52,505 24 28,712 61,068 228,575 371,342
Profit and total comprehensive income for the year - - - - - 15,561 15,561
As at 31 December 2025 458 52,505 24 28,712 61,068 244,136 386,903
Notes to the financial statements (company)
1. CORPORATE INFORMATION
The Company is incorporated and registered in England and Wales. The
Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower,
Singapore 079909. The registered office of the Company is located at Level
19, The Shard, 32 London Bridge Street, London, SE1 9SG United Kingdom.
The Company's ordinary shares are listed on AIM, a market regulated by the
London Stock Exchange plc.
The principal activity of the Company is that of investment holding in the
production and exploration of oil and gas.
2. BASIS OF PREPARATION
The Company meets the definition of a qualifying entity under FRS 100, and as
such these financial statements have been prepared in accordance with
Financial Reporting Standard 101 Reduced Disclosure Framework (FRS 101). The
financial statements have been prepared under the historical cost convention.
As permitted by s408 of the Companies Act 2006 the Company has elected not to
present its own statement of profit or loss and other comprehensive income for
the period. The profit/loss attributable to the Company is disclosed in the
footnote to the Company's statement of financial position. The auditor's
remuneration for the audit is disclosed in Note 11 of the consolidated
financial statements. The Company has also applied the following disclosure
exemptions under FRS 101:
· paragraphs 45(b) and 46 to 52 of IFRS 2 Share-based Payment
(details of the number and weighted average exercise prices of share options,
and how the fair value of goods or services received was determined), as
equivalent disclosures are included within the consolidated financial
statements;
· all requirements of IFRS 7 Financial Instruments: Disclosures, as
equivalent disclosures are included in the consolidated financial statements;
· paragraphs 91 to 99 of IFRS 13 Fair Value Measurement (disclosure
of valuation techniques and inputs used for fair value measurement of assets
and liabilities);
· paragraph 38 of IAS 1 Presentation of Financial Statements - the
requirement to disclose comparative information in respect of:
- paragraph 79(a)(iv) of IAS 1 (a reconciliation of the number of
shares outstanding at the beginning and end of the period); and
- paragraph 73(e) of IAS 16 Property, Plant and Equipment
(reconciliations between the carrying amount at the beginning and end of the
period).
· IAS 7 Statement of Cash Flows;
· paragraphs 30 and 31 of IAS 8 Accounting Policies, Changes in
Accounting Estimates and Errors (the requirement for the disclosure of
information when an entity has not applied a new IFRS that has been issued but
is not yet effective); and
· paragraph 17 of IAS 24 Related Party Disclosures (key management
compensation), and the other requirements of that standard to disclose related
party transactions entered into between two or more members of a Group,
provided that any subsidiary which is a party to the transaction is wholly
owned by such a member.
3. MATERIAL ACCOUNTING POLICY INFORMATION
The Company's accounting policies are aligned with the Group's accounting
policies as set out within the consolidated financial statements, with the
addition of the following:
Investment in subsidiary
Investment in subsidiary is held at cost less any accumulated allowance for
impairment losses. Investment in subsidiaries also consist of capital
contribution by the Company to its subsidiaries by assuming the ownership of
the LTIP awards previously granted by the former parent Company of the Group.
4. CRITICAL ACCOUNTING JUDGEMENTS AND KEY SOURCES OF ESTIMATION
UNCERTAINTY
In the process of applying the Company's accounting policies, the Directors
are required to make judgements, 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 following is the critical judgement and estimate that the Directors have
made in the process of applying the Company's accounting policies that have
the most significant effect on the amounts recognized in the financial
statements.
· Recoverability of the loan to a subsidiary, Jadestone Energy
Holdings Ltd
The recoverability of the loan is based on the evaluation of expected credit
loss. A considerable amount of estimation uncertainty exists in assessing
the ultimate realization of the loan, including the past collection history
from Jadestone Energy Holdings Ltd ("JEHL") and the estimated future
profitability of JEHL, with its sole source of income being dividend income to
be received from its subsidiaries. Accordingly, the Directors exercised
judgement in estimating the future profitability of JEHL's underlying oil and
gas operations.
In estimating the future profitability of the JEHL's subsidiaries, Directors
estimated the available reserves owned by the subsidiaries and performed
sensitivity analysis on the estimated reserves as disclosed in Note 3 of the
consolidated financial statements. Directors concluded that the subsidiaries
will be able to declare sufficient dividend income to JEHL based on the
estimated reserves and also after taking into the account the sensitivity
analysis as disclosed in Note 3 of the consolidated financial statements.
Directors also considered the future hydrocarbon prices in determining the
future profitability of the JEHL's subsidiaries. The future hydrocarbon price
assumptions used are highly judgemental and may be subject to increased
uncertainty given climate change and the global energy transition. Directors
further take into consideration the impact of climate change on estimated
future commodity prices with the application of the Paris aligned price
assumptions as disclosed in Note 3 of the consolidated financial statements.
Based on the analysis performed, the potential future reduction on the
hydrocarbon prices as impacted by the climate change and the global energy
transition will not significantly impact the future operating cash flows of
the subsidiaries. Accordingly, Directors estimate that the subsidiaries will
be able to declare sufficient dividend income to JEHL.
Accordingly, the recoverability assessment of the loan, together with other
intercompany balances and investments in subsidiaries, has been performed in
the context of impairment indicators identified under IAS 36, including the
Group's market capitalization being below its net assets. The Directors
concluded that, based on the impairment assessment performed, the loan is
recoverable and no impairment is required.
5. INVESTMENT IN SUBSIDIARY
2025 2024
US$'000 US$'000
Unquoted share, at cost - -*
Share-based payment:
At beginning of year 28,005 27,598
Capital contribution arising from share-based payments 1,312 407
At end of year 29,317 28,005
* Rounded to the nearest thousand.
The increase in investment in subsidiaries relates to equity-settled
share-based payments granted to employees of subsidiaries, which are treated
as capital contributions by the Company.
Details of the direct and indirect investments the Company holds are as
follows:
Name of the Company Place of incorporation
% voting rights and ordinary shares held 2025 % voting
rights and ordinary shares held 2024
Nature of business
Direct
Jadestone Energy Holdings Ltd ((1)) England and Wales 100 100 Investment
holdings
Jadestone Energy U.K plc ((1)(a)) England and Wales 100 - Investment
holdings
Name of the Company Place of incorporation % voting rights and ordinary shares held 2025 % voting
rights and ordinary shares held 2024
Nature of business
Indirect
Jadestone Energy (Australia) Pty Ltd ((2)) Australia 100 100 Production of oil & gas
Jadestone Energy (Australia Holdings) Pty Ltd ((2)) Australia 100 100 Investment
holdings
Jadestone Energy (CWLH) Pty Ltd ((2)) Australia 100 100 Production of oil & gas
Jadestone Energy (Eagle) Pty Ltd((2)) Australia 100 100 Production of oil & gas
Jadestone Energy Inc. ((3)) Canada 100 100 Investment
holdings
Jadestone Energy Ltd ((4)) Bermuda 100 100 Investment
holdings
Jadestone Energy Services Sdn Bhd ((5)) Malaysia 100 100 Administration
Jadestone Energy (PHT GP) Limited ((1)(b)) England and Wales - 100 Investment
holdings
Jadestone Energy UK Services Ltd ((1)) England and Wales 100 100 Administration
Jadestone Energy (PM) Inc. ((6)) Bahamas 100 100 Production of oil & gas
Jadestone Energy Pte Ltd ((7)) Singapore 100 100 Investment holdings & other financial services activities
Jadestone Energy (Singapore) Pte Ltd ((7)) Singapore 100 100 Investment holdings
Jadestone Energy (Lemang) Pte Ltd((7)) Singapore 100 100 Exploration
Jadestone Energy (Malaysia) Pte Ltd((7)) Singapore 100 100 Production of oil & gas
Jadestone Energy (Thailand) Pte Ltd((7)(b)) Singapore - 100 Investment holdings
Mitra Energy (Vietnam Nam Du) Pte Ltd ((7)) Singapore 100 100 Exploration
Mitra Energy (Vietnam Tho Chu) Pte Ltd ((7)) Singapore 100 100 Exploration
PHT Partners LP ((8)(b)) Delaware - 100 Investment holdings
Registered office addresses:
((1)) Level 19, The Shard, 32 London Bridge Street, SE1 9SG, London, United
Kingdom
((2)) Atrium Building Level 2, 168-170 St Georges Terrace, Perth WA 6000,
Australia
((3)) 10th Floor, 595 Howe St., Vancouver BC, V6C 2T5, Canada
((4)) 3(rd) Floor - Par la Ville Place, 14 Par la Ville Road, Hamilton HM08,
Bermuda
((5)) Level 15-2, Bangunan Faber Imperial Court, Jalan Sultan Ismail, 50250,
Kuala Lumpur, Malaysia
((6)) H&J Corporate Services Ltd, Ocean Centre, Montagu Foreshore, East
bay Street, P.O. Box
SS-19084, Nassau, Bahamas
((7)) 3 Anson Road #13-01, Springleaf Tower, Singapore 079909
((8)) CT Corporation, 1209 Orange St, Wilmington, DE 19801, United States
((a)) Jadestone Energy U.K. plc was incorporated on 30 July 2025.
((b)) On 16 April 2025, the Group entered into a sale and purchase agreement
to sell Jadestone
Energy (Thailand) Pte Ltd and its interest in the Sinphuhorm gas fields as
further disclosed in Note 24.
6. STAFF NUMBER AND COSTS
The Company had no employees in 2025 and 2024.
The aggregate remuneration comprised:
2025 2024
US$'000 US$'000
Non-executive Directors fee 550 701
550 701
7. RELATED PARTY TRANSACTIONS
The Company did not enter into any new loan with its subsidiary during the
year
Amount owing by subsidiaries are mainly related to payments on behalf, and
advanced provided to the subsidiaries The amount owing by subsidiaries are
non-trade in nature, unsecured, non-interest bearing and repayable on demand.
Amount owing to a subsidiary is mainly related to advances received for the
purpose of depositing the funds into the Company's bank account. The amounts
owing to subsidiaries are non-trade in nature, unsecured, non-interest bearing
and repayable on demand.
During the year, the Company entered into the following transactions with its
subsidiaries:
2025 2024
US$'000 US$'000
Loan to a subsidiary
At the beginning of the year 214,579 217,112
Loan provided 914 -
Repayment received (733) -
Unrealized foreign exchange differences 20,691 (2,533)
At the end of the year 235,451 214,579
2025 2024
US$'000 US$'000
Amount owing by and (to) subsidiaries
At the beginning of the year 128,776 78,606
Advances provided 6,430 12,056
Advances repaid (4,000) -
Payment on behalf by 1,060 39,289
Repayment received (11,008) (1,175)
Others (590) -
At the end of the year 120,668 128,776
Refer to Note 14 for further details on the Company's credit risk management
and ECL assessment.
8. SHARE CAPITAL AND SHARE PREMIUM ACCOUNT
Share capital Share premium account
No. of shares US$'000 US$'000
Issued and fully paid
As at 1 January 2024, at £0.001 each 540,766,574 456 51,827
Issued during the year 344,225 1 349
As at 31 December 2024 541,110,799 457 52,176
Issued during the year 1,051,916 1 329
As at 31 December 2025 542,162,715 458 52,505
During the year, 1,336,552 share options (2024: nil) were exercised and
issued. Additionally, 1,051,916 shares (2024: 344,225 shares) were issued to
meet the obligations with regards to the restricted shares 60 (#_ftn60) .
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.
9. DIVIDENDS
The Company did not declare any dividend during the year.
10. 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.
11. SHARE-BASED PAYMENTS RESERVE
Share-based payments reserve represents the cumulative value of share-based
payment expenses recognized in relation to equity-settled option granted under
the Group's share-based compensation schemes. The reserve is transferred to
share capital or retained earnings, as applicable, upon the exercise, lapse,
or cancellation of the related share-based instruments.
No share based payment expenses was recognized during the year of 31 December
2025 (2024: US$Nil),and therefore no charge has been included in the company's
statement of profit or loss,
During the year, US$0.3 million (2024: US$0.3 million) of restricted shares
was vested and has been reclassified from share-based payments reserve to
share capital as shown in Note 30.
The share-based payment expense during the year arose from share options,
performance shares and restricted shares 61 (#_ftn61) were awarded from 2022
to 2025.
In 2023 and 2024, the performance share grants were suspended by the
Remuneration Committee upon the Committee's recommendation. In consultation
with external advisor, the Remuneration Committee approved a Deferred Cash
Plan ("DCP") as part of the Long-Term Incentive ('LTI") cycle.
This was done to ensure that the LTI programme aligns the interests of the
senior leaders of the Group to the interests of shareholders and is effective
in retaining and incentivising our top talents.
DCP was awarded in October 2023 and April 2024, with a three-year vesting
period ending in 2026 and 2027, respectively. The performance measures for the
DCP are consistent with those applied to the performance shares. DCP has been
recognized in liabilities as disclosed in Note 40.
On 15 May 2019, the Company adopted, as approved by the shareholders, the
amended and restated stock option plan, the performance share plan, and the
restricted share plan (together, the "LTI Plans"), which establishes a rolling
number of shares issuable under the LTI Plans up to a maximum of 10% of the
Company's issued and outstanding ordinary shares at any given time. Options
under the stock option plan will be exercisable over periods of up to 10 years
as determined by the Board.
During the year, the Group has granted new share options, performance shares
and restricted shares as further disclosed below.
11.1 Share options
The Directors have applied the Black-Scholes option-pricing model, with the
following assumptions, to estimate the fair value of the options at the date
of grant:
Options granted on
20 November 2025 9 March 2022
Risk-free rate 3.95% to 4.07% 1.34% to 1.38%
Expected life 4.5 to 5.5 years 5.5 to 6.5 years
Expected volatility 62 (#_ftn62) 49.2% to 50.1% 63.0% to 66.7%
Share price GB£ 0.24 GB£ 1.01
Exercise price GB£ 0.24 GB£ 0.92
Expected dividends 0.00% 1.96%
11.2 Performance shares
In 2022, the performance measures for performance shares incorporate both a
relative and absolute total shareholder return ("TSR") calculation on a 70:30
basis to compare performance vs. peers (relative TSR) and to ensure alignment
with shareholders (absolute TSR).
During the year, the performance measures for performance shares incorporate a
TSR calculation and the Group's Environmental, Social, and Governance ("ESG")
performance on 65:35 basis.
Relative TSR: measured against the TSR of peer companies; the size of the
payout is based on Jadestone's ranking against the TSR outcomes of peer
companies.
Absolute TSR: share price target plus dividend to be set at the start of the
performance period and assessed annually; the threshold share price plus
dividend has to be equal to or greater than a 10% increase in absolute terms
to earn any pay out at all, and must be 25% or greater for target pay out.
A Monte Carlo simulation model was used by an external specialist, with the
following assumptions to estimate the fair value of the performance shares at
the date of grant:
Performance shares granted on
20 November 2025
9 March 2022
Risk-free rate 3.67% 1.39%
Expected volatility 63 (#_ftn63) 42.3% 53.1%
Share price GB£ 0.24 GB£ 1.01
Exercise price N/A N/A
Expected dividends 0.00% 1.71%
Post-vesting withdrawal date N/A N/A
Early exercise assumption N/A N/A
11.3 Restricted shares 64 (#_ftn64)
Restricted shares are granted to certain senior management personnel as an
alternative to cash under exceptional circumstances and to provide greater
alignment with shareholder objectives. These are shares that vest three
years after grant, assuming the employee has not left the Group. They are
not eligible for dividends prior to vesting.
The following assumptions were used to estimate the fair value of the
restricted shares at the date of grant, discounting back from the date they
will vest and excluding the value of dividends during the intervening period:
Restricted shares granted on
5 December 2025 20 November 2025 17 February 2025 29 January 2025 6 December 2024
2 June 2025 22 May 2025 22 August 2022 9 March 2022
Risk-free rate N/A N/A N/A N/A N/A N/A 3.67% 1.73% 1.39%
Share price GB£ 0.24 GB£ 0.24 GB£ 0.20 GB£ 0.21 GB£ 0.30 GB£ 0.90 GB£ 0.27 GB£ 0.90 GB£ 1.01
Expected dividends 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 1.73% 1.71%
The following table summarises the options/shares under the LTI plans
outstanding and exercisable as at 31 December 2025:
Performance shares Restricted shares Shares Options
Number of options Weighted average Weighted
exercise average Number
price GB£ remaining of options exercisable
contract life
As at 1 January 2024 2,217,103 344,225 19,266,121 0.48 5.37 16,508,516
Vested during the year - (344,225) 0.76 7.19 2,118,585
Expired unexercised during the year (967,794) - (125,418) 0.59 - (125,418)
Granted during the year - 1,242,000 - - - -
As at 31 December 1,249,309 1,242,000 19,140,703 0.45 4.67 18,501,683
2024
Vested during the year - (1,051,916) - 0.85 3.95 1,334,979
Expired unexercised during the year - - - - -
Cancelled during the year (49,544) - (8,249,247) - - (8,249,247)
Granted during the year 2,494,608 10,233,438 1,885,979 - - 1,885,979
As at 31 December 2025 3,694,373 10,423,522 12,777,435 0.48 4.72 13,473,393
The weighted average share price on the exercise date in 2025 is GB£0.22
Weighted average Weighted
Range of exercise average
exercise price GB£ remaining
Number of options price contract life
GB£
Share options exercisable as at 31 December 2024 18,501,683 0.26- 0.99 0.45 4.67
Share options exercisable as at 31 December 2025 13,473,393 0.24 - 0.99 0.48 4.72
12. OTHER PAYABLES
2025 2024
US$'000 US$'000
Other payables 1,014 938
Accruals 1,033 470
2,047 1,408
Other payables and accruals principally comprise amounts outstanding for
on-going business expenditures. The average credit period is less than 30
days. For most suppliers, no interest is charged on the payables in the first
30 days from the date of invoice. Thereafter, interest may be charged on
outstanding balances at varying rates of interest. The Company has financial
risk management policies in place to ensure that all payables are settled
within the pre-agreed credit terms.
13. 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 at 31 December 2025, the fair value of warrant liability
was US$0.03 million (2024: US$0.9 million). The movement in the fair value of
warrants liability of US$0.9 million is disclosed in Note 16.
The Directors have applied the Black-Scholes option-pricing model, with the
following assumptions, to estimate the fair value of the warrants as at
year-end:
2025 2024
Risk-free rate 3.8% 4.48%
Expected life 0.4 years 1.4 years
Expected volatility 65 (#_ftn65) 40.44% 59.5%
Share price GB£ 0.24 GB£ 0.24
Exercise price GB£ 0.50 GB£ 0.50
Expected dividends 0% 0%
14. FINANCIAL INSTRUMENTS
Material accounting policy information
Details of the significant accounting policies and methods adopted (including
the criteria for recognition, the bases of measurement, and the bases for
recognition of income and expenses), for each class of financial assets,
financial liabilities and equity instruments are disclosed in Note 3 to the
consolidated financial statements.
Categories of financial instruments
2025 2024
US$'000 US$'000
Financial assets
At amortized cost
Loan to a subsidiary 235,451 214,579
Amounts owing by subsidiaries 120,668 128,776
Cash and cash equivalents 3,469 979
Total financial assets 359,588 344,334
Financial liabilities
At amortized cost
Other payables and accruals 2,047 1,408
Total financial liabilities (excluding warrants liability) 2,047 1,408
Financial risk management objectives and policies
The Company's principal financial instruments arise directly from its
operations and include intercompany receivables and cash balances. The Company
is exposed to a variety of financial risks, including credit risk, liquidity
risk and foreign currency risk.
Given the nature of the Company as a holding and financing entity, its
exposure to financial risks is primarily concentrated within the Group. The
Company's overall risk management strategy focuses on safeguarding its
financial position by maintaining adequate liquidity, ensuring the credit
quality of counterparties, and monitoring exposure to foreign exchange
fluctuations.
Credit risk management
Credit risk is the risk of financial loss arising from a counterparty's
failure to meet its contractual obligations. The Company's exposure to credit
risk arises primarily from the loan to a subsidiary, amounts owing by
subsidiaries and cash and cash equivalents. Intercompany balances are
unsecured, non-interest bearing and repayable on demand and form part of the
Company's treasury and funding activities within the Group.
The Company's exposure is therefore largely concentrated in its subsidiaries.
This concentration risk is mitigated by the Company's control over these
entities and its ability to influence their financial and operating policies.
Management monitors the financial position, performance and funding
requirements of subsidiaries on an ongoing basis to ensure that credit risk
remains low and that subsidiaries are able to meet their obligations as they
fall due. Cash balances are held with reputable financial institutions with
high credit ratings.
Exposure to credit risk
As at the financial year end, the Company has no significant concentration
other than the loan to a subsidiary and amounts owing by subsidiaries of
US$235.4 million (2024: US$214.6 million) and US$120.7 million (2024: US$128.8
million).
The Company applies the expected credit loss ("ECL") model in accordance with
IFRS 9. As these balances are repayable on demand, the Company's exposure to
credit risk is limited to the period over which repayment may be demanded.
Management assesses the financial capacity of subsidiaries to repay these
balances at the reporting date, taking into consideration their net asset
position, liquidity, expected future cash flows and the availability of
ongoing Group support.
In assessing the recoverability of the loan to Jadestone Energy Holdings Ltd
("JEHL"), management exercised judgement and considered the expected future
cash flow generation of its underlying subsidiaries. This included evaluating
assumptions relating to hydrocarbon reserves, production profiles and
commodity prices, as well as incorporating climate-related considerations
through the application of Paris-aligned price assumptions. Sensitivity
analyses were performed on these key assumptions.
Based on the assessment, management expects that JEHL's subsidiaries will
generate sufficient cash flows to support dividend distributions, enabling
JEHL to meet its repayment obligations. Accordingly, the probability of
default is assessed to be low and any expected credit losses are considered
immaterial. No impairment allowance has been recognized. There were no
significant changes in credit risk during the year and no balances were past
due.
The Company does not anticipate the carrying amounts of financial assets at
the reporting date to differ materially from the amounts that will ultimately
be recovered. The maximum exposure to credit risk is represented by the
carrying amounts of financial assets as presented in the statement of
financial position.
Liquidity risk management
Liquidity risk is the risk that the Company will not be able to meet its
financial obligations as they fall due. The Company's exposure to liquidity
risk arises primarily from other payables and accruals, which are short-term
in nature.
The Company manages liquidity risk by maintaining sufficient cash and cash
equivalents and by monitoring its cash flow requirements on an ongoing basis.
In addition, given its position within the Group, the Company has access to
intercompany funding arrangements if required, providing an additional source
of liquidity support.
All financial liabilities are repayable on demand or within one year. Based on
existing cash balances, expected cash flows and available funding support,
management is satisfied that the Company has sufficient liquidity to meet its
obligations as and when they fall due.
Exposure to liquidity risk
As at 31 December 2025, the Company maintains a strong liquidity position,
supported by its substantial net asset base and minimal financial liabilities.
Total equity amounted to US$386.9 million (2024: US$370.0 million),
significantly exceeding total liabilities of US$2.0 million (2024: US$2.3
million).
In addition, current financial assets of US$124.2 million (2024: US$129.8
million) exceed current liabilities of US$2.1 million (2024: US$2.3 million),
further demonstrating the Company's strong ability to meet short-term
obligations. Cash and cash equivalents of US$3.5 million (2024: US$1.0
million) provide sufficient headroom for immediate liquidity needs.
Based on the above, management is satisfied that the Company has adequate
financial resources to meet its obligations as and when they fall due.
15. EVENTS AFTER THE END OF REPORTING PERIOD
The Company's events after the end of the reporting period are the same as
those disclosed in Note 46 of the consolidated financial statements of the
Group.
Glossary
2C resources, 2C best estimate contingent resource, being quantities of hydrocarbons which are
estimated, on a given date, to be potentially recoverable from known
accumulations but which are not currently considered to be commercially
recoverable
2P reserves, 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
AGM annual general meeting
AGPF Akatara gas processing facility
AIM Alternative Investment Market
ARO asset retirement obligation
bbls barrels
bbls/d barrels per day
boe barrel of oil equivalent
boe/d barrels of oil equivalent per day
Bscf billion standard cubic feet
CALM buoy catenary anchor leg mooring buoy, a floating offshore mooring point used to
load oil
Carbon dioxide equivalent (or CO(2)-e) standard unit used to compare and account for emissions from various GHGs
based on their global warming potential
CEO Chief Executive Officer
the Company Jadestone Energy plc
COO Chief Operating Officer
CWLH Cossack, Wanaea, Lambert and Hermes oilfields offshore Western Australia
DD&A depletion, depreciation and amortization
EBITDAX earnings before interest tax, depreciation, amortisation and exploration
expense
EPCI engineering, procurement, construction and installation
FDP field development plan
FPSO floating production storage and offloading vessel
GHG greenhouse gases, with three main gases including carbon dioxide (CO(2)),
methane (CH(4)) and nitrous oxide N(2)0.
the Group Jadestone Energy plc and its subsidiaries
GSPA gas sales and purchase agreement
HSE health, safety and environment
HSSE health, safety, security and environment
IAS International Accounting Standards
IFRS International Financial Reporting Standards
IOGP International Association of Oil & Gas Producers
km kilometer
LPG liquified petroleum gas
LTI lost-time injury
MMbbls million barrels
MMboe millions barrels of oil equivalent
MMscf/d million standard cubic feet of gas per day
Mscf thousand standard cubic feet of gas
ND/UM Nam Du and U Minh gas discoveries offshore Vietnam
Net Zero the state reached when an organisation's GHG emissions are reduced in line
with the goals of the Paris Agreement, and any remaining emissions that cannot
be further reduced are fully neutralised by like-for-like permanent removals
NOPSEMA Australia's National Offshore Petroleum Safety and Environmental Management
Authority
opex or opex/boe operating expenditure or operating expenditure per boe
PenMal or the PenMal Assets collectively, the assets offshore Peninsular Malaysia acquired by Jadestone in
2021
PETRONAS Petroliam Nasional Berhad, Malaysia's national oil and gas company
Petrovietnam Vietnam National Industry - Energy Group
PITA Malaysian petroleum income tax
PRMS June 2018 SPE/WPC/AAPG/ SPEE/SEG/SPWLA/EAGE Petroleum Resources Management
System
PRRT petroleum resource rent tax
PSC production sharing contract, a legal and financial framework governing
upstream activities in certain countries
PSF process safety fundamentals
QCA or the QCA Code 2023 Quoted Companies Alliance and its 2023 corporate governance code
R&M repairs and maintenance
RBL Facility the Group's US$200 million reserve-based lending facility
scf standard cubic foot of gas
Scope 1 emissions direct operational GHG emissions
Skua-11ST the side-track of the Skua-11 well at Montara which was drilled during 2025
US$ US dollar
VIU value in use
Working Capital Facility US$30 million debt facility with 31 December 2026 maturity
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.
1 (#_ftnref1) Certain 2024 comparative information has been reclassified.
Please see the Financial Review section of this document for further detail.
2 (#_ftnref2) Total production cost guidance is stated prior to audit
adjustments including non-cash inventory and lifting movements.
3 (#_ftnref3) Does not reflect any capital expenditure or abandonment spend
outside the Group's producing assets.
4 (#_ftnref4) Following the approval of the Field Development Plan ("FDP")
for Nam Du/U Minh gas field in Vietnam on 18 March 2026, approximately 32
MMboe of 2P reserves were recognized.
5 (#_ftnref5) 2025 production includes Sinphuhorm gas and condensate
production up to divestment in April 2025 in accordance with Petroleum
Resource Management Systems guidelines. However, in accordance with IAS 28,
the Sinphuhorm interest was accounted for as an associated undertaking and
only recognizing dividends received. Accordingly, revenue and production costs
associated with Sinphuhorm were excluded from the Group's financial results.
6 (#_ftnref6) The realized oil price represents the weighted average actual
selling price inclusive of premiums or discounts to Brent.
7 (#_ftnref7) 2025 revenue of US$408.1 million (2024: US$395.0 million)
includes a hedging gain of US$2.2 million (2024: hedging charge US$27.4
million) relating to the commodity swap contracts associated with the RBL
Facility.
8 (#_ftnref8) Certain 2024 comparative information has been reclassified. A
total of US$9.9 million was reclassified to production costs, comprising
US$9.8 million from administrative staff costs and US$0.1 million from other
expenses to operating costs, to better reflect the nature of technical office
costs. Accordingly, 2024 adjusted unit operating costs per barrel of oil
equivalent has been updated to reflect the revised production figures.
9 (#_ftnref9) Pre-tax impairment of US$126.0 million, primarily relating to
the impact of lower oil prices utilized by Jadestone's independent reserves
auditor on the balance sheet carrying values of Stag and Montara. Applying the
Australian corporate tax rate of 30% results in an after-tax impairment charge
of US$88.2 million.
10 (#_ftnref10) Adjusted unit operating costs per boe, adjusted EBITDAX and
net debt/cash are non-IFRS measures and are explained in further detail in the
Non-IFRS Measures section of this document.
11 (#_ftnref11) Drawn amounts under the RBL Facility were reduced from
US$200.0 million to US$150.0 million following principal repayments of US$33.3
million and US$16.7 million in April and September 2025, respectively.
12 (#_ftnref12) The local government in the Jambi province has an option to
take a 10% participating interest in the Lemang PSC, which, if exercised,
would reduce Jadestone's working interest to 90%. At the end of 2025, the
Jambi local government had initiated the process to formally assume it's 10%
participating interest.
13 (#_ftnref13) Proven and Probable Reserves for Jadestone's assets have
been prepared in accordance with the June 2018 SPE/WPC/AAPG/
SPEE/SEG/SPWLA/EAGE Petroleum Resources Management System ("PRMS") as the
standard for classification and reporting.
14 (#_ftnref14) Assumes oil equivalent conversion factor of 6,000 scf/boe.
Akatara production and reserves are reported at 90% interest, net to
Jadestone.
15 (#_ftnref15) Assumes oil equivalent conversion factor of 5,740 scf/boe.
16 (#_ftnref16) Contingent Resources based on Jadestone estimates as at 31
December 2025.
17 (#_ftnref17) 2025 production includes Sinphuhorm gas and condensate
production up to divestment in April 2025 in accordance with Petroleum
Resource Management Systems guidelines. However, in accordance with IAS 28,
the Sinphuhorm interest was accounted for as an associated undertaking and
only recognizing dividends received. Accordingly, revenue and production costs
associated with Sinphuhorm were excluded from the Group's financial results.
18 (#_ftnref18) The realized oil price represents the weighted average
actual selling price inclusive of premiums or discounts to Brent.
19 (#_ftnref19) 2025 revenue of US$408.1 million (2024: US$395.0 million)
includes a hedging gain of US$2.2 million (2024: hedging charge US$27.4
million) relating to the commodity swap contracts associated with the RBL
Facility.
20 (#_ftnref20) Certain 2024 comparative information has been reclassified.
A total of US$9.9 million was reclassified to production costs, comprising
US$9.8 million from administrative staff costs and US$0.1 million from other
expenses to operating costs, to better reflect the nature of technical office
costs. Accordingly, 2024 adjusted unit operating costs per barrel of oil
equivalent has been updated to reflect the revised production figures.
21 (#_ftnref21) Pre-tax impairment of US$126.0 million, primarily relating
to the impact of lower oil prices utilized by Jadestone's independent reserves
auditor on the balance sheet carrying values of Stag and Montara. Applying the
Australian corporate tax rate of 30% results in an after-tax impairment charge
of US$88.2 million.
22 (#_ftnref22) Adjusted unit operating costs per boe, adjusted EBITDAX and
net debt/cash are non-IFRS measures and are explained in further detail in the
Non-IFRS Measures section of this document.
23 (#_ftnref23) Other operating income, administrative staff costs and
general and administrative expenses adjusted figures are non-IFRS measures.
24 (#_ftnref24) Total capital expenditure was US$92.8 million (2024: US$74.4
million), comprising total capital expenditure paid of US$83.0 million (2024:
US$50.5 million), accrued capital expenditure of US$9.8 million (2024: US$18.8
million) and no capitalization of borrowing costs in 2025 (2024: US$5.1
million).
25 (#_ftnref25) Certain 2024 comparative information has been reclassified.
A total of US$9.9 million was reclassified to production costs, comprising
US$9.8 million from administrative staff costs and US$0.1 million from other
expenses to operating costs, to better reflect the nature of technical office
costs. Accordingly, 2024 adjusted unit operating costs per barrel of oil
equivalent has been updated to reflect the revised production figures.
26 (#_ftnref26) 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.
27 (#_ftnref27) Inventories written down represent reductions in carrying
amount to net realizable value recognized as an expense during the year. The
inventories written down are added back to the calculation as they are
non-cash, non-recurring adjustments that do not reflect the underlying cost of
production.
28 (#_ftnref28) 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).
29 (#_ftnref29) Workover costs are excluded to enhance comparability. The
frequency of workovers can vary across periods.
30 (#_ftnref30) Other income represents the rental income from a helicopter
rental contract (a right-of-use asset) to a third party.
31 (#_ftnref31) There were no non-recurring operations costs incurred in
2025. The non-recurring operational costs in 2024 primarily related to costs
incurred at Montara being interim tanker storage temporarily employed as a
result of the repair work relating to the storage tanks of the Montara Venture
FPSO.
32 (#_ftnref32) Non-recurring other repair and maintenance costs in 2025
predominantly related to tank cleaning and subsea well services maintenance at
Montara, CALM buoy coating remediation and export flowline pigging at Stag and
maintenance of the air cooler heat exchanger at Akatara. In 2024, this
non-recurring repair and maintenance costs predominately related to subsea
maintenance at Montara, CALM buoy coating remediation and maintenance pigging
of the export flowline at Stag and rectification costs of the cranes and
platforms at the PenMal Assets.
33 (#_ftnref33) Transportation costs includes the pipeline tariff at the
PenMal Assets and tanker costs at Stag and Montara associated with lifting
costs.
34 (#_ftnref34) 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.
35 (#_ftnref35) No cost incurred in 2025 related to PenMal Assets
non-operated asset operational costs. In 2024, PenMal Assets non-operated
assets operational costs 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.
36 (#_ftnref36) Gas production from the Sinphuhorm Asset before the disposal
on 16 April 2025 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.
37 (#_ftnref37) Certain 2024 comparative information has been reclassified.
A total of US$9.9 million was reclassified to production costs, comprising
US$9.8 million from administrative staff costs and US$0.1 million from other
expenses to operating costs, to better reflect the nature of technical office
costs. Accordingly, 2024 adjusted unit operating costs per barrel of oil
equivalent has been updated to reflect the revised production figures.
38 (#_ftnref38) Non-recurring opex in 2025 represents the other repair and
maintenance costs predominantly related to tank cleaning and subsea well
services maintenance at Montara, CALM buoy coating remediation and export
flowline pigging at Stag and maintenance of the air cooler heat exchanger at
Akatara. The costs in 2024 represents Montara interim tanker storage costs
which was temporarily employed as a result of the repair work relating to the
storage tanks of the FPSO. It also includes repair and maintenance costs
predominately related to CALM buoy coating remediation and maintenance pigging
of export flowline at Stag, subsea maintenance at Montara and rectification
costs of the cranes and platform at the Puteri Cluster.
39 (#_ftnref39) Includes business development, external funding sourcing,
refinancing and internal reorganization costs.
40 (#_ftnref40) A total of US$9.9 million of costs relating to technical
onshore office staff was reclassified from wages, salaries and fees (Note 8,
US$8.7 million), staff benefits in kind (Note 8, US$1.1 million) and corporate
costs (Note 11, US$0.1 million) to production costs. The reclassification was
made to more appropriately present the underlying production costs. The
reclassification had no impact on the Group's previously reported profit,
total equity or cash flows.
41 (#_ftnref41) US$5.7 million was reclassified within production costs from
other repairs and maintenance to operating costs for a more appropriate
presentation of the underlying. The reclassification had no impact on the
Group's previously reported profit, total equity or cash flows.
42 (#_ftnref42) A total of US$9.8 million of costs relating to technical
onshore office was reclassified from wages, salaries and fees (US$8.7 million)
and staff benefits in kind (US$1.1 million) to production costs (Note 6). The
reclassification had no impact on the Group's previously reported profit,
total equity or cash flows.
43 (#_ftnref43) Out of the total US$68.0 million, US$23.8 million was
recognized within administrative staff costs as disclosed in Note 9, while
US$30.6 million relating to manpower costs and US$13.6 million relating to
technical onshore office-based costs were recognized within production costs -
operating costs as disclosed in Note 6.
44 (#_ftnref44) A total of US$0.1 million of costs relating to technical
onshore office was reclassified from corporate costs to production costs (Note
6). The reclassification had no impact on the Group's previously reported
profit, total equity or cash flows.
45 (#_ftnref45) The closing adjustment represents the economic benefits of
production since the effective date and completion.
46 (#_ftnref46) 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.
47 (#_ftnref47) The offset of the deferred tax liabilities and deferred tax
assets are within respective tax jurisdiction.
48 (#_ftnref48) Restricted shares are granted to eligible employees and
Directors, subject to vesting conditions. Upon vesting, the shares are
transferred directly to recipients and recognized in share capital.
49 (#_ftnref49) Restricted shares are granted to eligible employees and
Directors, subject to vesting conditions. Upon vesting, the shares are
transferred directly to recipients and recognized in share capital.
50 (#_ftnref50) 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.
51 (#_ftnref51) Expected volatility was determined by calculating
Jadestone's average historical volatility of each trading day's log growth of
TSR over a period between the grant date and the end of the performance
period.
52 (#_ftnref52) Restricted shares are granted to eligible employees and
Directors, subject to vesting conditions. Upon vesting, the shares are
transferred directly to recipients and recognized in share capital.
53 (#_ftnref53) 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.
54 (#_ftnref54) 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.
55 (#_ftnref55) A total of US$1.8 million of non-current lease liabilities
in 2024 has been reclassified to current lease liabilities to conform with the
appropriate presentation, with no impact on total liabilities or equity.
56 (#_ftnref56) 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.
57 (#_ftnref57) These does not apply to trade receivables as the Group has
applied the simplified approach in IFRS 9 to measure the loss allowance at
lifetime ECL.
58 (#_ftnref58) The borrowings of US$151.3 million (2024: US$200.2 million)
represents the fair value of the balance. The gross outstanding balance as
at 31 December 2025 is US150.0 million (2024: US$200.0 million).
59 (#_ftnref59) Certain amounts in the prior year's consolidated statement
of profit or loss have been reclassified to conform with the current year
presentation. These reclassifications had no impact on total profit for the
year or total equity. Refer to Notes 6, 8, and 11 for further details.
60 (#_ftnref60) Restricted shares are granted to eligible employees and
Directors, subject to vesting conditions. Upon vesting, the shares are
transferred directly to recipients and recognized in share capital.
61 (#_ftnref61) Restricted shares are granted to eligible employees and
Directors, subject to vesting conditions. Upon vesting, the shares are
transferred directly to recipients and recognized in share capital.
62 (#_ftnref62) 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.
63 (#_ftnref63) Expected volatility was determined by calculating
Jadestone's average historical volatility of each trading day's log growth of
TSR over a period between the grant date and the end of the performance
period.
64 (#_ftnref64) Restricted shares are granted to eligible employees and
Directors, subject to vesting conditions. Upon vesting, the shares are
transferred directly to recipients and recognized in share capital.
65 (#_ftnref65) 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.
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Copyright 2019 Regulatory News Service, all rights reservedRecent news on Jadestone Energy
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