REG - Jadestone Energy PLC - 2024 Full-Year Results
20/05/2025 07:00
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RNS Number : 3062J Jadestone Energy PLC 20 May 2025
2024 Full Year Results
Delivering to expectations, increasing resilience, guidance maintained
20 May 2025-Singapore: Jadestone Energy PLC (AIM:JSE) ("Jadestone" or the
"Company"), an independent upstream company and its subsidiaries (the
"Group"), focused on the Asia-Pacific region, reports its consolidated audited
financial statements (the "Financial Statements"), as at and for the financial
year ended 31 December 2024.
The Company will host a webcast at 1:00 p.m. UK time today, details of which
can be found in the announcement below.
2024 operational performance demonstrates benefit of diversified portfolio
l Over 10 million manhours worked without a lost-time injury (LTI) across the
Group's Indonesia and Malaysia operations.
l Delivered record annual production of 18,696 boe/d in 2024 (+35%
year-on-year).
l Successful completion and start-up of the Akatara field, further
diversifying the Group's production base, with gas sales commencing in July
2024 and the contractual performance test completing in December 2024.
l 10% reduction in adjusted unit operating costs in 2024 to US$33.68/boe
(2023: US$37.24/boe)
l Independently audited 1P reserves by ERCE of 48.6 mmboe at year-end 2024,
with a 1P reserves replacement ratio of more than 200%, greatly increasing the
Group's resilience.
l Independently audited 2P reserves by ERCE of 68.3 mmboe at year-end 2024,
resulting in a 2P reserves replacement ratio of 104% and a 10-year 2P reserve
life, based on 2024 production
l Year-end 2024 2C resources increased by 19% year-on-year to 125.7 mmboe, or
18 years resource life based on 2024 production. Approximately 75% of the 2C
resource base relates to the significant resource contained in the Group's gas
discoveries offshore Vietnam.
Stable and resilient financial position
l 2024 revenues increased by 28% year-on-year to US$395.0 million (2023:
US$309.2 million)
l Adjusted EBITDAX for 2024 of US$127.9 million, a 41% increase year-on-year,
driven primarily the increase in revenues.
l Operating cash flow pre working capital for 2024 of US$70.5 million, a 93%
increase on 2023 (US$36.5 million)
l Net debt of US$104.8 million at 31 December 2024 (31 December 2023: US$3.6
million net debt) has reduced to US$54.2 million at 30 April 2025, reflecting
c.US$112.5 million of consolidated Group cash balances and US$167.0 million of
debt drawn under the Group's reserve-based lending facility (RBL Facility).
l Signed a US$30 million working capital facility with a 31 December 2026
maturity. The working capital facility will be used for general corporate
purposes, providing additional liquidity to the Group, if required.
l Available liquidity of US$142.5 million at 30 April 2025, including the
undrawn working capital facility referenced above.
l Approximately 1.7 mmbbls of hedges in place covering the nine months ending
30 September 2025 at a weighted average hedge price of US$69.07/bbl.
l Certain of Jadestone's shareholders have requested that the Company seek
authority to repurchase shares at the 2025 AGM on 20 June 2025.
Current trading and outlook - a strong start to 2025
l Strong portfolio performance year-to-date 2025, with production for the
first four months of 2025 averaging 20,830 boe/d, a 22% increase year-on-year
and an annual record for this period.
¡ Akatara has delivered robust performance year-to-date in 2025, with
gross production averaging approximately 6,200 boe/d and 96% facilities
uptime, both ahead of plan.
l All guidance metrics unchanged:
¡ 2025 average production of 18-21,000 boe/d (post Sinphuhorm sale).
¡ 2025 operating costs of US$250-300 million.
¡ 2025 capital expenditure of US$75-95 million.
¡ 2025-2027 free cash flow (pre debt servicing) guidance 1 of US$270-360
million.
l Active portfolio management with the sale of the Group's non-operated
Thailand assets in April 2025 for an upfront consideration of US$39.4 million
and contingent payments of US$3.5 million.
l Submission of the field development plan for the commercialization of the
Nam Du/U Minh (NDUM) discoveries offshore southwest Vietnam to Petrovietnam,
commencing the regulatory approval process.
l Skua-11ST well operations ongoing, to accelerate recovery of reserves from
the Skua structure and extending the economic life of the Montara field by one
year. Results expected in June 2025.
l Debottlenecking project at Akatara progressing, accelerating the
commercialization of up 3.5 mmboe of reserves.
l In line with previous announcements, Jadestone has been reviewing its
organizational and cost structure, with the aim of ensuring that the Group is
run as efficiently as possible and enhancing its resilience to oil price
cycles, while maintaining the highest safety standards. As part of this
review, the Group will reduce the headcount of its Australian onshore office
in Perth by approximately 25%. The targeted headcount reductions do not impact
the Group's offshore Australia workforce. Jadestone's Australian asset
portfolio remains a core focus for the Group and its growth ambitions.
l The Group continues to explore strategic acquisition opportunities to drive
value and deliver scalable growth.
Dr. Adel Chaouch, Executive Chairman, commented:
"We closed 2024 on a very positive note, with the notable achievements of
safely bringing Akatara onstream and doubling our interest in CWLH both
contributing to our record production for the year, reducing unit opex and
enhancing the resilience of the Group.
Jadestone's refreshed and reinvigorated management team is delivering on its
promises. We have seen a strong performance from our diverse portfolio so
far in 2025, delivering record production for the first four months of the
year and importantly, in line with guidance. Our focus on operational
excellence and maintaining high uptime levels across the portfolio is paying
off, providing confidence for our shareholders in our full year guidance and
targets, which are reiterated today. In particular, we are very pleased at
the initial performance of the Akatara field, where uptime and production
early in 2025 has been ahead of plan, and we are confident that the cash flows
and value from this asset will be the foundation of Jadestone's success for
years to come.
Our operational progress is being delivered against a backdrop of enhanced
macroeconomic uncertainty. Greater asset diversification due to successful
growth, the onset of fixed price gas production from Akatara, our near-term
oil price hedges and the premium to Brent for our oil sales means we are
well-placed to weather oil price volatility. We are also taking action to
make Jadestone a more resilient business to oil price cycles, by targeting
reductions in both operating costs and overheads. We have strengthened the
balance sheet with net debt reduced by approximately half in the first four
months of 2025 and we have put in place a new working capital facility,
resulting in liquidity at the end of April of US$142.5 million - a strong
position from which to continue executing our 2025 activity program.
Jadestone has a rare and compelling investment proposition. We have the
skillset that covers both mid-life oil assets and greenfield gas developments,
and a significant presence and platform to operate in three of the top five
upstream producing countries in the Asia-Pacific region. We continue to
actively look for opportunities to achieve the scale which is increasingly
important in the oil and gas sector, but we will only allocate capital in a
way that will be accretive to shareholders."
Dr. Adel Chaouch
EXECUTIVE CHAIRMAN
2024 SUMMARY
US$'000 except where indicated 2024 2023
( ) ( )
Total hours worked lost-time injury free (million) 4.93 4.55
Total recordable injury rate 2.51 0.86
Proven plus Probable Reserves (mmboe) - 31 December 68.3 68.0
Sales volume, total liquids and gas, barrels of oil equivalent (boes) 5,284,718 3,862,742
Production, boe/day(1) 18,696 13,813
Realized oil price per barrel of oil equivalent (US$/boe)(2) 85.21 87.34
Realized gas price per thousand standard cubic feet (US$/mcf) 3.91 1.53
Revenue(3) 395,036 309,200
Production costs (276,969) (232,772)
Impairment of oil and gas properties - (29,681)
Adjusted unit operating costs per barrel of oil equivalent (US$/boe)(4) 33.68 37.24
Adjusted EBITDAX(4) 127,895 90,647
(Loss)/Profit after tax (44,141) (91,274)
(Loss)/Earnings per ordinary share: basic & diluted (US$) (0.08) (0.18)
Operating cash flows before movement in working capital 70,526 36,499
Capital expenditure 74,459 115,882
Net (debt)/cash(4) at 31 December (104,774) (3,596)
Operational and financial summary
· Proven and Probable (2P) reserves at 31 December 2024 increased
slightly year-on-year to 68.3 mmboe (2023: 68.0 mmboe), driven by 6.7 mmboe
of new reserves associated with the acquisition of a further 16.67% stake in
the CWLH fields and minor upward revisions at Akatara and Sinphuhorm
offsetting production in the year of 6.8 mmboe. Total 2P reserve additions of
7.1 mmboe during 2024 resulted in a 104% 2P reserve replacement ratio for the
year.
· Production rose 35% year-on-year to a record 18,696 boe/d (2023:
13,813 boe/d), primarily due to the CWLH 2 acquisition (+1,816 bbls/d), a full
year of Montara production (+1,607 bbls/d) and commencement of production at
Akatara (+977 boe/d).
· Total sales volume of oil, gas, LPG and condensate in 2024 increased
by 36% to 5.3 mmboe (2023: 3.9 mmboe), reflecting the increase in production.
· Total revenue increased by 28% to US$395.0 million (2023: US$309.2
million) due to higher sales volumes, slightly offset by a lower realized oil
price. Total 2024 revenue includes a hedging loss of US$27.4 million (2023:
US$10.3 million) from commodity swap contracts associated with the RBL
Facility.
· The average realized oil price for the year before hedging was
US$85.21/bbl in 2024 (2022: US$87.34/bbl). The average realized price premium
for 2024 was US$3.76/bbl (2023: US$5.58/bbl). The lower premium year-on-year
reflects a shift in the weighting of sales, with a greater proportion of CWLH
crude and lower proportion of Stag crude in 2024 compared to 2023.
· Reported production costs totalled US$277.0 million in 2024, a 19%
increase from US$232.8 million in 2022. The majority (US$30.7 million) of the
increase is explained by the (non-cash) change in lifting and inventory
movements year-on-year.
¡ 2024 adjusted unit operating costs(3) of US$33.68/boe represented a 10%
decrease over the prior year (2023: US$37.24/boe) primarily due to lower
operating cost production at CWLH and Akatara added to the production mix
during the year.
· Impairment of oil and gas properties was nil in 2024, compared to
US$29.7 million in 2023 due to impairments at Stag and non-producing assets
offshore Malaysia.
· Adjusted EBITDAX for 2024 increased by 41.2% to US$127.9 million, up
from US$90.6 million in 2023, driven by the factors set out above.
· 2024 loss after tax of US$44.1 million (2023: US$91.3 million loss
after tax), driven by the factors set out above
· 2024 operating cash flow before movements in working capital of
US$70.5 million, a increase of 93% compared to 2023 (US$36.5 million).
· 2024 capital expenditure of US$74.5 million reduced 36% year-on-year
(2023: US$115.9 million), primarily due to the completion of the Akatara
development project.
· Net debt of US$105.0 million at 2024 year-end (2023 year-end: US$3.6
million), reflected a full drawdown of US$200.0 million from the RBL Facility
and total cash and cash equivalents of US$95.0 million.
¡ The scheduled RBL March 2025 redetermination concluded on 2 April 2025,
resulting in a borrowing base of US$167.0 million for the six month period
ending 30 September 2025, which is currently fully drawn.
(1) 2024 Production includes Sinphuhorm gas and condensate production in
accordance with Petroleum Resource Management Systems guidelines, however in
accordance with IAS 28 the investment is accounted for as an associated
undertaking and only recognizes dividends received. Accordingly, the revenue
and production costs associated with Sinphuhorm are excluded from the Group's
financial results.
(2 ) Realized oil price represents the actual selling price inclusive of
premiums or discounts to Brent.
(3) Revenue in 2024 of US$395.0 million (2023: US$309.2million) includes a
hedging loss of US$27.4 million (2023: US$10.3 million) from the commodity
swap contracts associated with the RBL Facility.
(4) Adjusted unit operating costs per boe, adjusted EBITDAX and net debt/cash
are non-IFRS measures and are explained in further detail in the Non-IFRS
Measures section of this document.
Enquiries
Jadestone Energy plc.
Phil Corbett, Head of Investor Relations +44 7713 687 467 (UK)
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
Peel Hunt LLP (Joint Broker) +44 (0) 20 7418 8900 (UK)
Richard Crichton / David McKeown / Georgia Langoulant
Camarco (Public Relations Advisor) +44 (0) 203 757 4980 (UK)
Billy Clegg / Georgia Edmonds / Poppy Hawkins jadestone@camarco.co.uk (mailto:jadestone@camarco.co.uk)
Full-year 2024 presentation webcast
The Company will host an investor and analyst presentation at 1:00 p.m. (UK
time) on Tuesday, 20 May 2025, including a question-and-answer session,
accessible through the link below:
Webcast link:
https://www.investis-live.com/jadestone-energy/681de341f8132e000ea6c65a/nehyi
(https://www.investis-live.com/jadestone-energy/681de341f8132e000ea6c65a/nehyi)
Event title: Jadestone Energy Full-Year 2024 Results
Time: 1:00 p.m. (UK time)
Date: 20 May 2025
To join the presentation by phone, please use the below dial-in details from
the United Kingdom or the link for global dial-in details:
United Kingdom (Local): +44 20 3936 2999
United Kingdom (Toll-Free): +44 800 358 1035
Global Dial-In Details:
https://www.netroadshow.com/events/global-numbers?confId=70236
(https://www.netroadshow.com/events/global-numbers?confId=70236)
Access Code: 722579
ENVIRONMENT, SOCIAL AND GOVERNANCE (ESG)
Jadestone is committed to being a responsible operator that contributes to an
orderly energy transition by helping to meet regional energy demand, while
bringing positive social and economic benefits for its stakeholders, local
communities and the people associated with its operations.
HSE performance
The Group's priority remains the health and safety of its staff, contractors
and communities in which it operates, along with ensuring that any negative
environmental impacts from operations are minimized.
2024 saw a significant increase in work hours, reaching 5.41 million (2023:
4.64 million), largely driven by intensified commissioning efforts at the
Akatara Gas Processing Facility (AGPF) in Indonesia. Lagging metrics were met
with zero life altering events, zero major environmental events and one LTI,
at a rate of 0.18 / million manhours, exceeding industry safety benchmarks
(the 2024 target was less than the 2023 IOGP average of 0.242). A lost-time
injury occurred at Montara when a worker injured his shoulder.
The Group experienced four high potential incidents in 2024, a reduction of
33% from 2023. Two were related to dropped objects and there were two
electrical near misses. Dropped objects were a focus in 2024, resulting in a
60% reduction year-on-year. Jadestone continues to learn from near misses and
share learnings, both internally and externally.
At the AGPF, construction was largely completed at the beginning of the year,
with the focus in first year half on equipment testing, pre-commissioning, and
commissioning, along with a successful workover campaign on five existing
wells supplying gas to the facility. On 18 June 2024, mechanical completion
was achieved at the plant, marking the start of final commissioning and
production ramp-up. First export gas was achieved on 31 July 2024 and the
72-hour performance test was completed on 9 December 2024. Completion of the
performance test marked the conclusion of the commissioning phase at Akatara,
with responsibility for day-to-day operations transitioning from the EPCI
contractor to Jadestone. During this busy period, Jadestone's team maintained
safe operations, logging over four million hours worked without an LTI.
One Tier 1 process safety event was recorded at the AGPF, where a gas detector
was activated due to a crack in the small bore piping on an export compressor.
The compressor was shut down, isolated and depressurized and an investigation
revealed that additional bracing was required to bring vibration within
acceptable levels. After additional bracing was installed, post start-up
checks confirmed vibration was within acceptable levels.
Net Zero interim targets
Jadestone's strategy for maximizing reserves from existing producing oil and
gas fields explicitly precludes frontier exploration and new greenfield
development, a position that is informed by the IEA's Net Zero Emissions by
2050 Scenario. The Group is well positioned to benefit from the energy
transition as a responsible steward of mid-life assets, committed to upholding
climate targets and achieving its Net Zero interim reduction targets.
The Group is committed to reduce Scope 1 and 2 GHG emissions (in tonnes of
CO(2)-e) from its operated assets by 20% by 2026 and by 45% by 2030, relative
to 2021 levels. This commitment applies to emissions from the Group's existing
operated assets. Jadestone will make best endeavours to retain GHG reduction
levels when integrating future acquisitions into the interim targets, subject
to reviews of GHG abatement opportunities.
The Group's gross Scope 1 GHG emissions during 2024 amounted to 587 kilo
tonnes CO(2)-e (2023: 480 kilo tonnes CO(2)-e(( 2 ))). The year-on-year
increase reflects several factors, including significantly higher uptime at
Montara during 2024 and the addition of the Akatara field to Jadestone's
producing portfolio. Jadestone does not consume any purchased electricity at
any of its operated sites. Its indirect, Scope 2, GHG emissions from the
consumption of purchased electricity at its offices and warehouses accounts
for less than 1% of Scope 1 and 2 GHG emissions combined.
Jadestone intends that its interim GHG emissions reduction targets will be
achieved through a combination of measures, ranging from operational GHG
reductions, including minimizing flaring, as well as reliance on carbon
credits within the regulatory schemes of Jadestone regions. For further
details, refer to Jadestone's 2024 Annual Report as well as the Sustainability
Report, which will be published by the end of May 2025.
Governance
The Board gained a variety of skillsets and experience throughout 2024 and
into early 2025 with the longer-term objective to ensure that the Board is
sized appropriate to the Company's scale and ambition, while maintaining
appropriate capabilities and adhering to corporate governance standards.
Joanne Williams was appointed on 25 January 2024 as an independent
Non-Executive Director. Dr. Adel Chaouch was appointed to the Board on 25
March 2024 as an independent Non-Executive Director and elected as Chair of
the Board on 27 March 2024 after Dennis McShane stepped down. Additionally,
both Lisa Stewart and Robert Lambert stepped down from the Board effective 25
March 2024.
Linda Beal was appointed as an independent Non-Executive Director and Audit
Committee Chair on 9 May 2024. Iain McLaren did not seek re-election at the
Company's AGM and stepped down from the Board on 13 June 2024.
Andrew Fairclough was appointed as Executive Director and Chief Financial
Officer (CFO) on 29 October 2024 replacing the Group's former CFO, Bert-Jaap
Dijkstra, who stepped down as CFO and Executive Director on the same date.
During the second half of 2024, the Board evaluated the performance of the
Group and its management team, comparing actual outcomes against targets and
the resulting share price performance. After consulting material shareholders
of the Company, the Board subsequently decided that a change in Jadestone's
management team was required to best position the Group for future success. As
a result, Paul Blakeley stepped down as Executive Director, President, and CEO
effective 5 December 2024. The Board decided that Dr. Chaouch, with his
extensive upstream experience and management roles, would be best placed to
provide leadership, through combining the CEO role with his existing duties as
Chairman of the Board. Dr. Chaouch's appointment as Executive Chairman is on a
fixed-term basis, with appropriate incentives to ensure alignment with
shareholders and drive the success of the Group. At the same time and in
alignment with the QCA Code guidance and good governance practice, Linda Beal
was appointed as Senior Independent Director.
Given the management changes highlighted above, and while a search for a Chief
Executive Officer was progressed, the Board concluded that Joanne Williams had
the experience and skills to support the management team through this period.
She agreed to take an operational role as Chief Operating Officer on a fixed
term basis. After taking external advice, the Non-Executive Directors
determined that Joanne Williams would remain an independent Non-Executive
Director while performing her management role during this period.
On 16 January 2025, David Mendelson was appointed as an independent
Non-Executive Director and Cedric Fontenit stepped down as an independent
Non-Executive Director effective 20 January 2025.
The Board is progressing the appointment of an appropriate candidate as CEO.
OPERATIONAL REVIEW
Producing Assets
Australia
Montara Project (100% working interest, operated)
The Montara fields averaged 5,262 bbls/d in 2024, compared to 3,655 bbls/d in
2023. The year-on-year increase is primarily explained by higher uptime and
availability of the Montara Venture FPSO in 2024, after Montara production was
shut-in during early 2023 for repairs and maintenance activity on the FPSO's
storage tanks. Montara production in the second half of 2024 also benefitted
from the return to production of the H6 and Swift-2 wells, which had been
offline due to mechanical issues.
Following the significant activity on the FPSO's oil storage tanks since 2022,
the Montara Venture's storage capacity has now increased to over 600,000
barrels 3 . Increasing oil storage availability allowed for the temporary
shuttle tanker offloading arrangement to be phased out during the fourth
quarter of 2024, reducing transportation costs. The Group expects to resume
the FOB sale of larger cargoes of Montara crude from mid-2025 onwards, further
reducing lifting-related costs.
The Group's main capital activity during 2025 is the drilling of the Skua-11
sidetrack well (Skua-11ST), which commenced in April. This well has dual
objectives of decommissioning the original Skua-11 well and drilling a
sidetrack into the Skua structure up-dip of the original Skua-11 well path.
Based on pre-drill expectations, a successful Skua-11ST well would accelerate
recovery of reserves from the Skua structure and extend the economic life of
the Montara Project by one year.
In total, seven cargoes totaling 1.9 mmbbls (2023: five cargoes of 1.2 mmbbls)
were lifted from Montara in 2024, with an average realization of US$83.68/bbl
(consisting of an average Brent price of US$80.20/bbl and average premium of
US$3.48/bbl). This compares to an average realization of US$84.79/bbl in 2023
(Brent US$80.97/bbl and premium US$3.82/bbl).
CWLH (33.33% working interest, non-operated)
On 14 February 2024, the Group completed the acquisition of an additional
16.67% working interest in the Cossack, Wanaea, Lambert and Hermes oil fields
offshore western Australia, doubling its working interest to 33.33%.
During 2024, Jadestone's net production from the CWLH fields averaged 3,711
bbls/d, compared to 1,896 bbls/d in 2023. The year-on-year change is primarily
explained by the increase in the Group's working interest referenced above.
However, the CWLH asset outperformed expectations in 2024 with average
production 6% ahead of the Group's forecast, driven by better than expected
reservoir performance.
Following engagement with the CWLH joint venture, total abandonment trust fund
payments associated with the acquisition of the additional 16.67% interest
were finalized at US$83.8 million, all of which was paid in 2024.
The Group lifted two cargoes of 1.3 mmbbls (2023: one cargo of 0.7 mmbbls)
from CWLH in 2024 for an average realization of US$82.38/bbl (consisting of an
average Brent price of US$83.20/bbl and an average discount of US$0.82/bbl).
This compares to a realization of US$82.81/bbl in 2023 (Brent US$83.18/bbl and
discount of US$0.37/bbl) for the one cargo lifted in 2023.
Stag (100% working interest, operator)
Stag field production averaged 2,006 bbls/d in 2024, compared to 2,671 bbls/d
in 2023.
Production in 2023 benefited from the initial production impact of the
Stag-50H and 51H wells drilled in November 2022. Stag field production in 2024
reflected the impact of weather-related downtime in the early part of the
year, and mechanical issues in several wells which required workovers to
restore output. Attempts to restore production from the Stag-48H well during
2024 and early 2025 were unsuccessful, with further activity on this well
under review.
Several initiatives are currently underway to address the well reliability and
uptime issues at Stag that have impacted production in recent years, with Stag
production increasing during the first half of 2025 as a result. The Stag
field's operating cost structure is also being reviewed to ensure that asset
cash flows and the economic life of the field can be maximized.
Work continues on the Stag-52H and 53H infill drilling targets to improve
payback duration and returns prior to a sanction decision on either well.
The Group sold three Stag cargoes totaling 0.7mmbbls in 2024 (2023: four
cargoes totaling 1.0 mmbbls). Premiums for Stag crude have remained strong,
with the average realization for 2024 sales of US$95.93/bbl (Brent
US$82.18/bbl and premium US$13.75/bbl), compared to an average 2023
realization of US$94.16/bbl (Brent US$81.13/bbl and premium US$13.03/bbl).
Indonesia
Akatara (100% working interest 4 , operator)
The Akatara field is located within the Lemang PSC onshore Sumatra in
Indonesia. Akatara was previously developed as an oil field, prior to being
redeveloped by Jadestone to commercialize gas, condensate and LPG reserves
located in shallower zones.
Development activity at Akatara finished in the first half of 2024,
culminating in a declaration of mechanical completion at the Akatara Gas
Processing Facility in June 2024, and the introduction of reservoir gas from
one of the five production wells, with condensate production also commencing
at this point.
Commissioning of the facility continued during the second half of 2024, with
facility uptime and production volumes steadily increasing as several
commissioning issues were encountered and addressed.
The Akatara gas development successfully completed its formal EPCI contract
performance test in December 2024. This required a continuous 72-hour test of
the AGPF at full production rates, representing the daily contract quantity
under the Akatara gas sales agreement and associated LPG and condensate
production. This milestone marked the conclusion of the commissioning phase at
Akatara, with responsibility for day-to-day operations at the AGPF
transitioning from the EPCI contractor to Jadestone.
Akatara production, on an annual average basis, was 977 boe/d in 2024 (2023:
nil). A total of 1.2 bcf of gas was sold in 2024 at an average price of
US$5.97/mcf, with initial Akatara LPG and condensate sales totaling
approximately 150,000 barrels, which were sold for a weighted average price of
US$56.69/bbl.
Akatara performance in early 2025 has been ahead of expectations, with 96%
AGPF uptime year-to-date and gross production averaging approximately 6,200
boe/d. The focus in 2025 is to implement a series of minor plant upgrades
during the scheduled annual shut down in May 2025, which will enhance the
overall resiliency of the AGPF.
The Group continues to progress its plans to increase the capacity of the AGPF
through a debottlenecking project. It is now expected that the debottlenecking
project will follow a phased approach, with an increase in AGPF capacity in
mid-2025 through modifying and optimizing plant gas processing, with the
remainder of the proposed increase in capacity coming in the second half of
2026 following engineering, procurement and installation of additional
processing equipment. The phased approach will result in an earlier increase
in plant capacity than previously expected, with lower upfront costs and is
still expected to accelerate the production of 3.5 mmboe of reserves.
The HSE performance at Akatara has been highly impressive, with over eight
million manhours having been worked to date in both the development and
production phase without a lost-time injury.
Malaysia
PM323 PSC (60% working interest, operator)
The PM323 PSC produced an average of 3,484 bbls/d net to Jadestone's working
interest in 2024 (2023: 2,203 bbls/d). The year-on-year increase was due to
the positive impact of the Group's infill drilling program on the East Belumut
field in late 2023.
The Group is progressing plans for further infill drilling on the East Belumut
field in 2026, focusing on the undrained southwestern area of the field
discovered during the 2023 drilling campaign.
A total of 0.6 mmbbls (2023: 0.4 mmbbls) were lifted from the PM323 PSC during
2024, with an average realization of US$84.30/bbl (2023: US$86.99/bbl).
PM329 PSC (70% working interest, operator)
The PM329 PSC produced an average of 1,501 boe/d net to Jadestone's working
interest in 2024, consisting of 1,024 bbls/d of oil and 2.9 mmcf/d of gas
(2023: 2,085 boe/d, consisting of 1,461 bbls/d of oil and 3.7 mmcf/d of gas).
The year-on-year decrease is due to natural decline.
A total of 0.3 mmbbls of oil (2023: 0.3 mmbls) were lifted from the PM329 PSC
in 2024, with an average realization of US$83.89/bbl (2023: US$86.82/bbl). In
addition, approximately 1.0 bcf of gas was sold at an average realization of
US$1.60/mcf.
Puteri Cluster (100% working interest, operator)
In July 2024, Jadestone was awarded a 100% participating interest in the
Puteri Cluster Production Sharing Contract (the Puteri Cluster PSC, previously
referred to as the SFA Cluster PSC) offshore Peninsular Malaysia. The Puteri
Cluster PSC covers an area of 348km(2) in shallow water offshore Peninsular
Malaysia located adjacent to the Group's existing operated PM323 and PM329
PSCs and is surrounded by the PM428 PSC (see below).
The Puteri Cluster PSC contains the Penara, Puteri-Padang and North Lukut
fields, assets in which Jadestone previously held a 50% non-operated interest
(through the PM318 and AAKBNLP PSCs) following the Group's entry into Malaysia
in August 2021.
Jadestone currently estimates that the Puteri Cluster PSC contains
approximately 15.4 mmbbls of gross 2C contingent resources. The Group is
continuing its technical assessment of the Puteri Cluster PSC ahead of a
decision to submit a field development and abandonment plan to PETRONAS.
PM428 PSC (60% working interest, operator)
In January 2024, Jadestone was awarded a 60% operated interest in the PM428
PSC offshore Peninsular Malaysia. The PM428 PSC is adjacent to the PM323 and
PM329 PSCs and surrounds the Puteri Cluster PSC (referenced above). The PM428
PSC carries a minimal financial commitment to reprocess existing seismic and
contains several prospects which, in a success case, could be developed
through existing infrastructure currently operated by Jadestone
Thailand
Sinphuhorm (9.52% working interest, non-operated)
During 2024, the Sinphuhorm field produced an average of 1,755 boe/d (1,734
boe/d gas and 21bbls/d of condensate). Production for 2023 averaged 1,303
boe/d (expressed as an annual average from completion of the Sinphuhorm
acquisition on 23 February 2023). The year-on-year increase in 2024 reflected
the partial ownership in 2023, strong gas demand in northern Thailand in the
second half of 2024, the successful commissioning of a booster compression
project in 2024 and robust performance from recent infill wells.
Due to a lack of influence over the day-to-day operational activities at
Sinphuhorm, the Group did not recognize its share of revenues and production
costs, instead recognizing dividend income when received from APICO LLC.
Dividends of US$8.2 million were received in 2024 (2023: US$4.3 million).
On 16 April 2025, the Group announced that it had sold its Thailand interests
to a subsidiary of PTTEP, the Thailand national oil and gas company, for a
cash consideration of US$39.4 million, with a further US$3.5 million in
contingent payments depending on future license extensions.
Pre-production Assets
Vietnam
Block 51 PSC (100% working interest, operator) and Block 46/07 PSC (100%
working interest, operator)
In January 2024, the Group announced that it had signed a Heads of Agreement
(HoA) with Petrovietnam Gas Joint Stock Corporation for the Gas Sales and
Purchase Agreement (GSPA) relating to the Nam Du and U Minh (NDUM) gas fields
development, located in the Block 46/07 and Block 51 Production Sharing
Contracts in shallow waters offshore southwest Vietnam.
Following signature of the HoA, the Group commenced detailed negotiations over
a fully termed GSPA, which are currently well advanced. The HoA also allowed
for the submission in March 2025 of an updated field development plan (FDP)
for the NDUM fields, the approval of which is required before a final
investment decision can be taken. The FDP specifies the development concept
for the NDUM fields, associated capital and operating cost estimates, and a
schedule to first gas.
The Block 46/07 PSC includes a commitment to drill an additional exploration
well. In February 2024, Jadestone submitted an application to extend the
commitment period and proposed that the well be incorporated into the Nam Du
field development drilling program. As at 31 December 2024, the Field
Development Plan (FDP) incorporating the commitment well, had not yet been
submitted for approval. The company has recognised a provision of US$10.0
million in respect of this obligation. Subsequent to the year-end, the
Company submitted the FDP on 18 March 2025.
The Group continues to work with Petrovietnam and other government entities to
obtain a suspension of the relinquishment obligation for Block 51, which
contains the Tho Chu discovery.
Reserves and resources
Total 2P Reserves(1) (net, mmboe)
Australia Malaysia(2) Indonesia(2) Thailand(3) Total Group
Opening balance, 1 January 2024 31.6 9.2 23.3 3.9 68.0
Acquisitions 6.7 - - - 6.7
Technical revisions (0.2) - 0.1 0.5 0.4
Production (4.0) (1.8) (0.4) (0.6) (6.8)
Ending balance, 31 December 2024 34.1 7.4 23.0 3.8 68.3
As at 31 December 2024, the Group had 2P Reserves of 68.3 mmboe, a slight
increase compared with 31 December 2023, after accounting for production in
2024. New 2P reserves of 6.7 mmboe were booked on the closing of an additional
16.67% interest in CWLH fields in February 2024. There were minor upward
technical revisions at the Akatara field in Indonesia and Sinphuhorm in
Thailand, with the latter due to higher forecast gas demand through to the end
of license expiry in 2031. Collectively, these 7.1 mmboe of positive revisions
were sufficient to offset production of 6.8 mmboe, representing 104% 2P
reserve replacement during the year.
ERC Equipoise Limited independently evaluated the Group's year-end 2024
reserves.
Total 2C Contingent Resources(4) (net, mmboe)
Australia Malaysia Indonesia(2) Thailand(3) Vietnam(2) Total Group
Opening balance, 1 January 2024 5.1 1.2 0.9 4.4 93.9 105.6
Acquisitions 5.5 - - - - 5.5
Transfer to 2P reserves - - - - - -
Technical revisions - 15.1 - (0.4) - 14.7
Ending balance, 31 December 2024 10.6 16.3 0.9 4.0 93.9 125.7
Group 2C resources as at 31 December 2024 are estimated at 125.7 mmboe, an
increase of 19% year-on-year, mainly reflecting the addition of 2C resources
associated with the Puteri Cluster PSC award during the year and the CWLH 2
acquisition in February 2024. Approximately 75%, or 93.9 mmboe, of the Group
2C resources at 31 December 2024 relates to the significant resource contained
in the Group's gas discoveries offshore Vietnam.
(1) Proven and Probable Reserves for Jadestone's assets have been prepared in
accordance with the June 2018 SPE/WPC/AAPG/ SPEE/SEG/SPWLA/EAGE Petroleum
Resources Management System ("PRMS") as the standard for classification and
reporting.
(2) Assumes oil equivalent conversion factor of 6,000 scf/boe.
(3) Assumes oil equivalent conversion factor of 5,740 scf/boe. The Group
disposed of its assets in Thailand on 16 April 2025 to a subsidiary of
Thailand's national oil and gas company, PTTEP, for an initial consideration
of US$39.4 million and contingent payments of US$3.5 million.
(4) Contingent Resources based on Jadestone estimates as at 31 December 2024,
except for Vietnam 2C resources which are based on ERCE Competent Person's
Report effective 31 December 2017
FINANCIAL REVIEW
The following table provides select financial information of the Group, which
was derived from, and should be read in conjunction with, the consolidated
financial statements for the year ended 31 December 2024.
US$'000 except where indicated 2024 2023
( ) ( )
Production, boe/ day(1) 18,696 13,813
Oil and liquids sales, barrels of oil equivalent (boes) (2) 4,764,875 3,634,991
Realized oil price per barrel of oil equivalent (US$/bbl)(3) 85.21 87.34
Gas sales, thousand standard cubic feet (mcf) 2,216,652 1,366,505
Realized gas price per thousand standard cubic feet (US$/mcf) 3.91 1.53
Sales volume for LPG and condensates, barrels (bbls) 150,401 -
Realized LPG and condensate price per barrel (US$/bbl)(3) 56.69 -
Revenue(4) 395,036 309,200
Production costs (276,969) (232,772)
Adjusted unit operating costs per barrel of oil equivalent (US$/boe)(5) 33.68 37.24
Adjusted EBITDAX(5) 127,895 90,647
Unit depletion, depreciation and amortization (US$/boe) 12.45 14.14
Impairment of assets - (29,681)
(Loss) before tax (43,435) (102,766)
(Loss) after tax (44,141) (91,274)
(Loss) per ordinary share: basic and diluted (US$) (0.08) (0.18)
Operating cash flows before movement in working capital 70,526 36,499
Capital expenditure 74,459 115,882
Net (debt)/cash ( )at 31 December (104,964) (3,596)
Benchmark commodity price and realized price
The actual average realized price in 2024 decreased by 2% to US$85.21/bbl,
from US$87.34/bbl in 2023. The benchmark Dated Brent price remained virtually
flat at US$81.45/bbl in 2024, compared to US$81.76/bbl in 2023. The reduction
in the realized price was predominately due to the decline in the average
premium to US$3.76/bbl in 2024, compared to US$5.58/bbl in 2023. The lower
premium reflected a change in the composition of sale volumes, with CWLH crude
comprising a higher proportion of sale volumes in 2024, compared to higher
premium Stag barrels in 2023. The Stag premium in 2024 averaged US$13.75/bbl
(2023: 13.03/bbl), compared to the CWLH average discount at US$0.82/bbl (2023:
average discount at US$0.37/bbl).
(1) Production includes Sinphuhorm gas and condensate production in accordance
with Petroleum Resource Management Systems guidelines, non-IFRS measure.
However, in accordance with IAS 28 the investment is accounted for as an
associated undertaking and the Group only recognizes dividends received.
Accordingly, the revenue and production costs from the Sinphuhorm Asset are
excluded from the Group's financial results.
(2) Sales volumes include oil, condensate and LPG.
(3) Realized oil price represents the actual selling price inclusive of
premiums or discounts.
(4) Revenue in 2024 and 2023 includes a hedging charge of US$27.4 million and
U$10.3 million respectively from the commodity swap contracts associated with
the RBL Facility.
(5) Adjusted unit operating cost per boe, adjusted EBITDAX and net cash are
non-IFRS measures and are explained in further detail in the Non-IFRS Measures
section in this document.
Production and liftings
Production for 2024 was 18,696 boe/d, an increase of 4,883 boe/d compared to
13,813 boe/d in 2023. This overall increase was driven by the following key
factors:
· The acquisition of a further 16.67% interest in CWLH increased
production to 3,711 bbls/d in 2024 compared to 1,896 bbls/d in 2023;
· Montara achieved a full year production in 2024 of 5,262 bbls/d,
compared to 2023 of 3,655 bbls/d, after production resumed in March 2023
following repairs to the Montara Venture FPSO's tanks;
· Akatara completed commissioning and start-up activities with
first commercial production achieved on 31 July 2024 at annual average rate of
977 boe/d;
· Production from the PenMal Assets increased by 697 boe/d in 2024
to 4,985 boe/d (2023: 4,288 boe/d) due to the successful infill drilling
campaign at the end of 2023 on the PM323 PSC; and
· Sinphuhorm production increased year-on-year in 2024 to 1,755
boe/d (2023: 1,303 boe/d) reflecting a full-year of asset ownership,
commissioning of a booster compressor at the field and strong gas demand in
northern Thailand.
The increase was partly offset by:
· Production at Stag decreased by 665 bbls/d in 2024 to 2,006
bbls/d (2023: 2,671 bbls/d) due to extended downtime caused by adverse weather
conditions and downhole mechanical issues in wells which required workovers.
Throughout the year, the Group completed 21 crude liftings compared to 19 in
2023, leading to oil sales totalling 4.8 mmbbls, up from 3.6 mmbbls in 2023.
Condensate and liquefied petroleum gas (LPG) produced from Akatara lifted a
combined 0.15 mmbbls starting the second half of 2024 upon commencement of of
Akatara field (2023: nil)
The Group recorded a sale of 1,047.1 mmcf and 1,169.6 mmcf of gas from the
PenMal Assets and Akatara respectively in 2024, compared to 1,366.5 mmcf of
gas in 2023 from the PenMal Assets.
Revenue
The Group generated net revenue after hedging effects of US$395.0 million in
2024, an increase of 28% compared to 2023 of US$309.2 million. The increase of
US$85.8 million was predominately due to:
· An increase in lifted volumes by 1.1 mmbbls year-on-year
resulting in increased revenue of US$96.3 million; and
· Akatara generated US$14.9 million after first gas on 31 July
2024, consisting of US$6.4 million from gas sales, US$4.3million of LPG and
US$4.2 million of condensate sales.
The increase was partly offset by:
· Hedging losses increased US$17.1 million to US$27.4 million in
2024, based on a weighted average hedging price of US$69.07/bbl from the
commodity swap contracts associated with the RBL Facility compared to loss of
US$10.3 million in 2023 (the hedging contracts commenced in October 2023);
· Lower average realized price in 2024 of US$85.21/bbl (2023:
US$87.34/bbl), resulting in a revenue decrease of US$7.7 million; and
· Revenue generated in 2024 from PM329 gas sales decreased US$0.5
million to US$1.6 million in 2024 compared to US$2.1 million in 2023.
Production costs
Production costs increased by 19% in 2024 to US$277.0 million, from US$232.8
million in 2023, amounting to an increase of US$44.2 million.
2024 2023 Variance
US$'000 US$'000 US$'000
Operating costs 111,736 98,723 13,013
Workovers 20,797 17,562 3,235
Logistics 26,928 34,109 (7,181)
Repairs and maintenance 70,304 55,572 14,732
Tariffs and transportation costs 8,451 7,502 949
Supplementary payments and royalties 17,342 16,056 1,286
Decommissioning expenses - 12,545 (12,545)
Underlift, (overlift) and crude inventories 21,411 (9,297) 30,708
movement
276,969 232,772 44,197
The year-on-year increase was predominately due to the following factors:
· Operating costs increased by US$13.0 million to US$111.7 million in
2024, compared to US$98.7 million in 2023, due to several factors. The
increase includes US$15.4 million for CWLH due to the additional interest
acquired in February 2024. Operating costs at the PenMal Assets were higher by
US$4.2 million due to inventory adjustments. Akatara incurred US$4.8 million
of operating costs following first gas in July 2024. These increases were
offset by reductions at Montara and Stag which decreased by US$11.4 million,
due to reduced costs for crude tanker hire rates, lower diesel consumption by
US$4.4 million and the non-recurring waste disposal cost for NORMs (naturally
occurring radioactive material) was US$1.0 million lower in 2024.
· Workover costs increased by US$3.2 million to US$20.8 million
in 2024, compared to US$17.6 million in 2023. This rise was primarily driven
by complex well-integrity repairs at Stag, which cost US$2.2 million more than
the previous year. Additionally, the PenMal Assets incurred US$2.9 million in
workover costs during 2024 for well integrity and performance improvements.
· Logistical costs decreased by US$7.2 million to US$26.9 million
in 2024 from US$34.1 million, primarily due to a US$4.9 million reduction at
Montara following the unavailability of helicopters, which led to lower
standing charges, and a US$3.0 million decrease at PenMal's Puteri Cluster due
to minimal offshore activity after the demobilization of the FPSO. These
reductions were partially offset by a US$0.6 million increase at Stag, where
multiple cyclone events in 2024 required more frequent use of support vessels
and helicopters compared to 2023.
· Repairs and maintenance (R&M) increased by US$14.7 million,
rising to US$70.3 million in 2024 from US$55.6 million in 2023. Akatara
recorded US$6.0 million R&M following the start of commercial production.
Montara's costs rose by US$3.3 million due to an ROV campaign and subsea
inspections, while the PenMal Assets incurred an additional US$3.0 million
from engine overhauls on producing assets and topsides flushing and pipeline
preservation works at the Puteri Cluster facilities. Stag saw a net increase
of US$2.4 million for one-off remedial works on the CALM buoy and export
pipeline.
· Supplementary payments and royalties increased by US$1.3
million in 2024 due to higher production-based royalties at Montara, CWLH and
Akatara. This was offset with a decrease at PenMal Assets.
· The PenMal Assets incurred a one-off decommissioning expense of
US$12.5 million in 2023, related to decommissioning activities on the Bunga
Kertas FPSO at the PNLP Assets.
· Underlift, overlift and crude inventories movement (non-cash)
increased US$30.7 million driven by the second acquisition of 16.67% of the
CWLH assets in February 2024. The acquired underlift was valued at US$40.5
million and was included in inventory movements until it was sold as part of
the March 2024 lifting. Apart from the CWLH underlift, the net year-on-year
movement generated a credit of US$9.8 million reflecting a decrease in
inventory movements across the asset portfolio.
The adjusted unit operating cost per barrel of oil equivalent in 2024 was
US$33.68/boe (2023: US$37.24/boe) (please refer to the Non-IFRS measures
section later in this document). The decrease was primarily due to the change
in the production mix, principally the lower operating costs at Akatara and
CWLH.
Depletion, depreciation and amortization (DD&A)
DD&A charges increased to US$91.4 million in 2024, up from US$76.1 million
in the prior year. The rise was primarily driven by higher production at
Montara, which accounted for an additional US$16.8 million, and the
commencement of production at Akatara, contributing US$2.6 million. These
uplifts were partially offset by a US$5.6 million reduction at Stag due to
lower output, and a US$1.6 million decrease at CWLH, attributed to the
application of IFRS 3 (Business Combinations) purchase price accounting
following the increase in the Group's interest in February 2024.
In 2024, the Group's right-of-use asset depreciation increased by US$0.9
million to US$16.2 million compared to US$15.3 million in 2023. This increase
was primarily attributable to the full-year depreciation effect of leases that
were either signed or renewed during 2023.
There was a decrease in the overall depletion cost on a unit basis, reducing
to US$12.45/boe in 2024 from US$14.14/boe in 2023. This reduction was mainly
due to the reclassification of Akatara's capitalized development costs to
production assets for depletion, which resulted in a relatively low unit
depletion cost of US$3.66/boe for Akatara in 2024.
Staff costs
Total staff costs in 2024 were US$65.0 million (2023: US$56.2 million),
comprising US$30.6 million (2023: US$26.0 million) in relation to offshore
employees (recorded under production costs), and US$34.4 million (2023:
US$30.2 million) for office-based employees. The average number of employees
during the year was 422 (2023: 409), with the additional staff costs and
headcount year-on-year mainly due to Akatara commencing production and onshore
support in Australia. During the year, there was compensation for loss of
office amounting to US$2.3 million, plus, US$0.2 million of payroll tax for
the departure of the former CEO, Mr A. Paul Blakeley. These amounts were
accrued in 2024 and paid in 2025.
Other expenses and allowance for expected credit losses
2024 2023 Variance
US$'000 US$'000 US$'000
Non-recurring corporate costs 1,397 3,602 (2,205)
Recurring corporate costs and other expenses 17,009 11,742 5,267
Allowance for expected credit losses 457 - 457
Allowance for slow moving inventories 1,670 655 1,015
Assets written off 1,775 5,114 (3,339)
Net foreign exchange loss 2,008 1,728 280
24,316 22,841 1,475
Other expenses increased US$1.5 million in 2024 to US$24.3 million (2023:
US$22.8 million), predominately due to:
· Non-recurring corporate costs fell by US$2.2 million to US$1.4
million in 2024. This reduction included US$0.9 million of business
development fees, and US$0.5 million of financing fees. The 2023 total was
US$3.6 million, with US$2.2 million for business development, US$0.8 million
for reorganization costs, US$0.4 million for an equity fundraising and US$0.2
million for financing fees.
· Recurring corporate costs increased by US$5.3 million to US$17.0
million in 2024 (2023: US$11.7 million). While general administrative expenses
for office operations, professional services and travel remained consistent
year-over-year, the increase was due to a full-year of dividend based
royalties at Sinphuhorm, withholding taxes and higher professional fees
related to executive recruitment, consulting fees and other expenses.
· The allowance for expected credit losses in 2024 of US$0.5
million (2023: Nil) represents a specific bad debt provision created against a
customer during the year.
· The allowance for slow-moving materials and spares more than
doubled to US$1.6 million in 2024 from US$0.7 million in 2023, due to an
increase in slow-moving inventory related to supplies.
· Assets written off decreased by US$3.3 million in 2024, with
total write-offs of US$1.8 million compared to US$5.1 million in 2023. The
2024 write-offs mainly related to US$1.8 million for obsolete Montara
materials and spares. In contrast, the 2023 write-offs were higher, including
US$3.1 million from the cancellation of the Skua-12 well project and US$2.1
million for obsolete inventory.
· Net foreign exchange loss of US$2.0 million in 2024 (2023: US$1.7
million) mainly arising from the Group's receivables denominated in Malaysian
Ringgit ("MYR") due to the volatility of MYR against USD towards the end of
2024.
Finance costs
Finance costs in 2024 were US$45.1 million (2023: US$41.8 million), an
increase of US$3.3 million predominately due to:
· Interest fees for the RBL Facility increased by US$8.3 million to
US$16.4 million (2023: US$8.1 million). The increase reflects higher
borrowings and full year of interest and expenses compared to a partial period
of expense incurred in 2023 (the RBL Facility was signed in May 2023).
· Accretion fees for the Asset Retirement Obligation (ARO)
increased by US$2.4 million to US$22.6 million (2023: US$20.2 million),
predominantly due to the additional ARO recognized for CWLH working interest
acquired in 2024;
The above increased was offset by:
· The warrant reserve generated a decrease of US$3.5 million in 2024,
as the reserve was created during the 2023 equity raise,
resulting in a US$3.5 million charge in that year. In 2024, there was no
movement on the reserve. The revaluation of the
warrant liability is included in Other Financial Gains.
· Upfront fees and interest associated with the working capital
facility and financing facilities decreased by US$1.3 million to US$2.4
million, compared to US$3.7 million in 2023.
· The accretion expense for Akatara long-term VAT receivables
decreased by US$1.0 million to US$0.2 million in 2024 compared to US$1.2
million in 2023.
· Changes in fair value of contingent payments in 2024 of US$0.1
million, a US$0.8 million decrease compared to US$0.9 million in 2023.
· RBL commitment fees in 2024 of US$0.1 million, a US$0.3 million
decrease compared to US$0.4 million in 2023.
Other income
The Group generated US$29.6 million of other income in 2024, an increase of
US$10.7 million (2023:US$18.9 million) predominately due to:
· The change in ARO provisions generated a gain of US$13.8 million
in 2024 (2023: US$Nil) primarily related to CWLH (US$11.0 million) and the
PenMal Assets (US$2.8 million), driven by changes in underlying assumptions.
· Interest income increased US$3.0 million, due to the CWLH
decommissioning trust fund interest increasing US$3.4 million to US$6.3
million (2023: US$2.9 million) following the additional contributions made
during the year and an additional US$0.3 million to US$1.3 million (2023:
US$1.0 million) earned from the placement of fixed deposits.
The above increases were offset by:
· Other provisions decreased by US$6.5 million to a gain of US$1.1
million (2023: US$7.6 million) due to a change in underlying assumptions for
provisions for contingent payments and manpower related provisions.
· The Montara helicopter rebate decreased US$0.7 million to US$5.7
million in 2024, compared to US$6.4 million in 2023. The lower rebate in 2024
was due to services being provided for only one helicopter unit, compared to
two units in 2023.
Other financial gains
Other financial gains increased US$2.6 million in 2024, due to the revaluation
of the warrant liability. The warrant liability is revalued at each reporting
date. This gain reflects a reduction in the liability from US$3.5 million in
2023 to US$0.9 million in 2024.
Share of result of associates
During 2024, the Group recognized its share of profits from the Sinphuhorm
field amounting to US$1.5 million (2023: US$2.6 million). The Group disposed
of its Thailand assets in April 2025.
Impairment
No impairment was recorded in 2024. In 2023, the Group impaired the Stag oil
and gas properties by US$17.4 million and US$12.3 million impairment on the
PNLP Assets oil and gas properties due to revised ARO estimates.
Taxation
The tax expense of US$0.7 million in 2024 (2023: US$11.5 million of tax
credit) includes a current tax charge of US$7.1 million (2023: US$10.8
million) and a deferred tax credit of US$6.4 million (2023: deferred tax
credit of US$22.3 million).
During the year, tax payments comprised US$14.7 million (2023: US$5.3 million)
for Australian corporate taxes. Additionally, there were US$12.3 million
(2023: US$7.5 million) in Malaysian petroleum income tax (PITA) payments.
The weighted average effective tax rate for operating jurisdictions in
Australia and Malaysia was 35% in 2024, based on the profit-making entities
within each jurisdiction, compared to 54% in 2023. There was an increase in
the deferred tax asset during 2024, resulting from the income tax credits that
are generated as trading losses which are carried forward for offset against
future taxable profits.
US$'000 2024 2023
US$'000 US$'000
( ) ( ) ( )
Loss before tax (43,435) (102,766)
Expected effective tax rate 35% 54%
Tax at the country level effective rate (15,335) (55,494)
Effect of different tax rates in loss making jurisdictions 5,011 13,975
Malaysia PITA tax losses on non-operated PSCs 8,275 10,060
Utilization of PRRT credits (10,031) 17,795
PRRT tax refund (1,700) 1,735
Non-deductible expenses 839 399
Income not subject to tax (1,897) -
Deferred tax permanent differences 5,473 2,155
PRRT permanent differences (1,149) (4,269)
Deferred tax asset not recognised 12,049 -
Adjustment in respect to prior years (829) 2,152
Tax expense/(credit) for the year 706 (11,492)
Australia taxes
The Australian corporate income tax rate is 30% and PRRT is 40%, with the
latter being cash based and income tax deductible. The combined standard
effective tax rate is 58%, with the actual effective tax rate of 26% in 2024
(2023: 42%) being lower due to the utilization of PRRT credits brought forward
and current year business tax losses. Montara and CWLH have approximately
US$4.1 billion (2023: US$3.8 billion) and US$802.4 million (2023: US$493.4
million) of unutilized PRRT credits, respectively. Both assets are not
expected to incur any PRRT over their economic lives. There was an increase in
the deferred tax asset during 2024, resulting from income tax credits as
trading losses are carried forward for offsetting against future taxable
profits.
Malaysia taxes
Malaysian PITA is a PSC based tax on petroleum operations at the rate of 38%.
There are no other material taxes in Malaysia.
Indonesia taxes
The Indonesia corporate income tax rate is applied at 30% of Indonesia
corporate taxable income. Corporate and Dividend Tax ("C&D") is calculated
at 20% of sales revenue less certain permitted deductions and is tax
deductible for Indonesia corporate income tax purposes. There is no tax
expense during the year for Indonesia tax due to the Lemang asset as it is not
in a taxable income position.
RECONCILIATION OF CASH
US$'000 2024 2023
Cash and cash equivalents at the beginning of year 153,404 123,329
Revenue 395,036 309,200
Other operating income 6,889 6,574
Production costs (276,969) (232,772)
Staff costs (34,016) (29,431)
General and administrative expenses (20,414) (17,072)
Operating cash flows before movements in working 70,526 36,499
capital
Movement in working capital 10,491 6,837
Placement of decommissioning trust fund for CWLH (83,773) (41,000)
Assets
Net tax paid (27,907) (14,461)
Investing activities
Purchases of intangible exploration assets, oil and gas (50,510) (109,524)
properties, and plant and equipment(1)
Cash paid on acquisition of Sinphuhorm Assets - (27,853)
Dividends received from associate 8,660 3,842
Cash received on acquisition of CWLH 5,236 -
Other investing activities 7,492 4,451
Financing activities
Net proceeds from issuance of shares - 50,964
Shares repurchased - (2,084)
Repayment of lease liabilities (18,985) (17,171)
Total drawdown of borrowings 43,000 232,000
Repayment of borrowings - (75,000)
Repayment of costs and interests of borrowings (19,086) (13,260)
Other financing activities (3,322) (4,165)
Total cash and cash equivalent at the end of year 95,226 153,404
(1) Total capital expenditure was US$74.4 million (2023: US115.9 million),
comprising total capital expenditure paid of US$50.5 million (2023: US$109.5
million), accrued capital expenditure of US$18.8 million (2023: US$4.0
million) and capitalization of borrowing costs of US$5.1 million (2023: US$2.4
million ).
NON-IFRS MEASURES
The Group uses certain performance measures that are not specifically defined
under IFRS, or other generally accepted accounting principles. These non-IFRS
measures comprise adjusted unit operating cost per barrel of oil equivalent
(adjusted opex/boe), adjusted EBITDAX, outstanding debt, and net debt/cash.
The following notes describe why the Group has selected these non-IFRS
measures.
Adjusted unit operating costs per barrel of oil equivalent (Adjusted opex/boe)
Adjusted opex/boe is a non-IFRS measure used to monitor the Group's operating
cost efficiency, as it measures operating costs to extract hydrocarbons from
the Group's producing reservoirs on a unit basis.
Adjusted opex/boe is based on total production cost and incorporates lease
payments linked to operational activities, net of any income derived from
those right-of-use assets involved in production. The calculation excludes
factors such as oil inventories movement, underlift/overlift adjustments,
inventory write-downs, workovers, non-recurring repair and maintenance
expenses, transportation costs, supplementary payments associated with the
PenMal Assets, expenses related to non-operating assets and DD&A. This
definition aims to ensure better comparability between periods.
The adjusted production costs are then divided by total produced barrels of
oil equivalent for the prevailing period to determine the unit operating cost
per barrel of oil equivalent.
US$'000 except where indicated 2024 2023
Production costs (reported) 276,969 232,772
Adjustments
Lease payments related to operating activity(1) 17,538 16,155
Underlift, overlift and crude inventories movement(2) (21,411) 9,297
Workover costs(3) (20,797) (17,562)
Other income(4) (5,731) (6,375)
Non-recurring operational costs(5) (8,840) (19,654)
Non-recurring repair and maintenance(6) (2,850) (1,773)
Transportation costs(7) (8,451) (7,502)
PenMal Assets supplementary payments and Australian royalties(8) (17,342) (16,056)
PenMal non-operated assets operational costs(9) (262) (19,273)
Adjusted production costs 208,823 170,029
Total production (barrels of oil equivalent) 6,200,334 4,566,060
Adjusted unit operating costs per barrel of oil equivalent 33.68 37.24
(1) Lease payments related to operating activities are lease payments
considered to be operating costs in nature, including leased helicopters for
transporting offshore crews. These lease payments are added back to reflect
the true cost of production.
(2) Underlift, overlift and crude inventories movement are added back to the
calculation to match the full cost of production with the associated
production volumes (i.e., numerator to match denominator).
(3) Workover costs are excluded to enhance comparability. The frequency of
workovers can vary significantly, across periods.
(4) Other income represents the rental income from a helicopter rental
contract (a right-of-use asset) to a third party.
(5) Non-recurring operational costs mainly related to costs incurred at
Montara being interim tanker storage temporarily employed as a result of the
repair work relating to the storage tanks of the Montara Venture FPSO.
(6) Non-recurring repair and maintenance costs in 2024 predominately related
to subsea maintenance at Montara, CALM buoy coating remediation and
maintenance pigging of the export flowline at Stag and rectification costs of
the cranes and platforms of at one of the PenMal Assets. The cost in 2023
predominately related to the repair of a gas turbine generator at the PenMal
Assets PM329 PSC.
( )
(7) The transportation costs includes the pipeline tariff at the PenMal Assets
and tanker costs at Stag and Montara associated with lifting costs.
(8) The supplementary payments are required under the terms of PSCs based on
Jadestone's profit oil after entitlements between the government and joint
venture partners. The Australian royalties are related to an Australian
Government mandated decommissioning cost recovery levy on all upstream
producers in the country, plus royalties payable from the CWLH fields to the
local state government .
(9) Similar to 2023, PenMal non-operated assets operational costs in 2024
refer to the operating costs incurred at the PNLP Assets, which are excluded
as the costs incurred were mainly related to the preservation of facilities
and subsea infrastructure and do not contribute to production.
Adjusted EBITDAX
Adjusted EBITDAX is a non-IFRS measure which does not have a standardized
meaning prescribed by IFRS. This non-IFRS measure is included because
management uses the measure to analyse cash generation and financial
performance of the Group.
Adjusted EBITDAX is defined as profit from continuing activities before income
tax, finance costs, interest income, DD&A, other financial gains and
non-recurring expenses.
The calculation of adjusted EBITDAX is as follow:
US$'000 2024 2023
Revenue 395,036 309,200
Production costs (276,969) (232,772)
Administrative staff costs (34,423) (30,197)
Other expenses and allowance for expected credit losses (24,316) (22,841)
Share of results of associate 1,553 2,640
Other income, excluding interest income 22,122 14,404
Other financial gains 2,611 -
Unadjusted EBITDAX 85,614 40,434
Non-recurring
Net loss from oil price and foreign exchange derivatives 27,417 10,395
Non-recurring opex(1) 11,952 40,700
Oil and gas properties written off 1,423 3,067
Change in provision - Lemang PSC contingent payments - (7,653)
Others(2) 1,489 3,704
42,281 50,213
Adjusted EBITDAX 127,895 90,647
( )
(1) Non-recurring opex in 2024 represents Montara interim tanker storage costs
which was temporarily employed as a result of the repair work relating to the
storage tanks of the FPSO. It also includes repair and maintenance costs
predominately related to CALM buoy coating remediation and maintenance pigging
of export flowline at Stag, subsea maintenance at Montara and rectification
costs of the cranes and platform of AAKBNLP asset at PenMal. The cost in 2023
mainly consisted of one-off operational costs and major maintenance/well
intervention activities, in particular operating costs and FPSO rectification
costs incurred at the PNLP Assets, Montara interim tanker storage, diesel fuel
consumption by the FPSO during production shutdown and to power the
reinjection compressor during production start-up. It also includes repair and
maintenance costs related to the repair of a gas turbine generator at PenMal
Assets PM329 PSC.
(2) Includes business development costs, external funding sourcing costs and
internal reorganization costs.
Net cash/debt
Net (debt)/cash is a non-IFRS measure which does not have a standardized
definition prescribed by IFRS. Management uses this measure to analyse the net
borrowing position of the Group.
US$'000 2024 2023
Borrowings (principal sum) (200,000) (157,000)
Cash and cash equivalents 95,226 153,404
Net (debt)/cash (104,774) (3,596)
Net (debt)/cash is defined as the sum of cash and cash equivalents and
restricted cash, less the outstanding principal sum of borrowings.
Consolidated Statement of Profit or Loss and Other Comprehensive Income
for the year ended 31 December 2024
2024 2023
Notes USD'000 USD'000
Consolidated statement of profit or loss
Revenue 4 395,036 309,200
Production costs 5 (276,969) (232,772)
Depletion, depreciation and amortisation 6 (91,407) (76,141)
Administrative staff costs 7 (34,423) (30,197)
Other expenses 10 (23,859) (22,841)
Allowance for expected credit losses 10 (457) -
Impairment of oil and gas properties 12 - (29,681)
Share of results of associate accounted for using the equity 23 1,553 2,640
method
Other income 13 29,614 18,855
Finance costs 14 (45,134) (41,829)
Other financial gains 15 2,611 -
Loss before tax (43,435) (102,766)
Income tax (expense)/credit 16 (706) 11,492
Loss for the year (44,141) (91,274)
Loss per ordinary share
Basic and diluted (US$) 17 (0.08) (0.18)
Consolidated statement of other comprehensive income
Loss for the year (44,141) (91,274)
Other comprehensive income
Items that may be reclassified subsequently to profit or loss:
Loss on unrealised cash flow hedges 34 (14,849) (30,509)
Hedging loss reclassified to profit or loss 4, 34 27,417 10,322
12,568 (20,187)
Tax (expense)/credit relating to components of other 16 (3,770) 6,056
comprehensive loss
Other comprehensive income 8,798 (14,131)
Total comprehensive income for the year (35,343) (105,405)
Total comprehensive income is attributable to the equity holders of the
parent.
Consolidated Statement of Financial Position as at 31 December 2024
31 December 31 December
2024 2023
Notes USD'000 USD'000
Assets
Non-current assets
Intangible exploration assets 19 91,323 79,564
Oil and gas properties 20 422,239 457,202
Plant and equipment 21 10,591 10,462
Right-of-use assets 22 16,111 31,099
Investment in associate 23 19,544 26,651
Other receivables 27 274,124 141,860
Deferred tax assets 25 44,898 26,774
Cash and cash equivalents 28 888 1,008
Total non-current assets 879,718 774,620
Current assets
Inventories 26 44,602 33,654
Trade and other receivables 27 55,044 124,379
Tax recoverable 13,863 4,085
Cash and cash equivalents 28 94,338 152,396
Total current assets 207,847 314,514
Total assets 1,087,565 1,089,134
Equity and
liabilities
Equity
Capital and reserves
Share capital 29 457 456
Share premium account 29 52,176 51,827
Merger reserve 31 146,270 146,270
Share-based payments reserve 32 27,730 27,673
Capital redemption reserve 33 24 24
Hedging reserve 34 (5,333) (14,131)
Accumulated losses (202,490) (158,349)
Total equity 18,834 53,770
31 December 31 December
2024 2023
Notes USD'000 USD'000
Non-current liabilities
Provisions 35 664,951 503,170
Borrowings 36 122,978 131,729*
Lease liabilities 37 5,308 18,746
Other payables 39 17,282 16,966
Derivative financial instruments 40 - 6,708
Deferred tax liabilities 25 59,620 65,829
Total non-current liabilities 870,139 743,148
Current liabilities
Borrowings 36 77,212 22,844*
Lease liabilities 37 12,243 14,118
Trade and other payables 39 92,793 117,984*
Derivative financial instruments 40 7,618 13,972*
Warrants liability 41 931 3,469
XXX
Provisions 35 5,542 108,525
Tax liabilities 2,253 11,304
Total current liabilities 198,592 292,216
Total liabilities 1,068,731 1,035,364
TOTAL EQUITY AND LIABILITIES
Total equity and liabilities 1,087,565 1,089,134
*US$15.8 million of borrowings reported as at 31 December 2023 has been
reclassified from non-current to current as disclosed in Note 36. US$4.5
million of derivative financial liabilities instruments as at 31 December 2023
has been reclassified to trade and other payables as disclosed in Note 39 and
Note 40.
Consolidated Statement of Changes in Equity for the year ended 31 December
2024
Share premium Share-based payments reserve Capital redemption reserve
Share capital account Merger reserve USD'000 USD'000 Hedging reserve Accumulated losses
USD'000 USD'000 USD'000 USD'000 USD'000 Total
USD'000
As at 1 January 2023 339 983 146,270 26,907 21 - (64,991) 109,529
Loss for the year - - - - - - (91,274) (91,274)
Other comprehensive - - - - - (14,131) - (14,131)
income for the year
Total comprehensive - - - - - (14,131) (91,274) (105,405)
income for the year
Share-based payments - - - 766 - - - 766
(Note 8)
Shares issued (Note 29) 120 52,846 - - - - - 52,966
Transaction costs - (2,002) - - - - - (2,002)
associated with issuance
of shares (Note 29)
Share repurchased (3) - - - 3 - (2,084) (2,084)
(Note 29)
Total transactions with 117 50,844 - 766 3 - (2,084) 49,646
owners, recognised
directly in equity
As at 31 December 2023 456 51,827 146,270 27,673 24 (14,131) (158,349) 53,770
Share premium Share-based payments reserve Capital redemption reserve
Share capital account Merger reserve USD'000 USD'000 Hedging reserve Accumulated losses
USD'000 USD'000 USD'000 USD'000 USD'000 Total
USD'000
As at 1 January 2024 456 51,827 146,270 27,673 24 (14,131) (158,349) 53,770
Loss for the year - - - - - - (44,141) (44,141)
Other comprehensive - - - - - 8,798 - 8,798
income for the year
Total comprehensive - - - - - 8,798 (44,141) (35,343)
income for the year
Share-based payments - - - 407 - - - 407
(Note 8)
Shares issued (Note 29) 1 349 - (350) - - - -
Total transactions with 1 349 - 57 - - - 407
owners, recognised
directly in equity
As at 31 December 2024 457 52,176 146,270 27,730 24 (5,333) (202,490) 18,834
Consolidated Statement of Cash Flows for the year ended 31 December 2024
2024 2023
Notes USD'000 USD'000
Operating activities
Loss before tax (43,435) (102,766)
Adjustments for:
Depletion, depreciation and amortisation 6 91,407 76,141
Share-based payments 7 407 766
Assets written off 10 1,775 5,114
Allowance for slow moving inventories 10 1,670 655
Allowance for expected credit losses 10 457 -
Reversal of provision 13 (14,936) (7,653)
Unrealised foreign exchange gain (297) (177)
Impairment of oil and gas properties 12 - 29,681
Interest income 13 (7,492) (4,451)
Finance costs 14 45,134 41,829
Other financial gains 15 (2,611) -
Share of results of associate 23 (1,553) (2,640)
Operating cash flows before movements in working 70,526 36,499
capital
Working capital movements:
Increase in trade and other receivables (63,613) (80,900)
Increase in inventories (29,954) (15,655)
(Decrease)/Increase in trade and other payables (39,623) 62,392
Cash (used in)/generated from operations (2,756) 2,336
Net tax paid (27,907) (14,461)
Net cash used in operating activities (30,663) (12,125)
Investing activities
Cash paid for acquisition of Sinphuhorm Assets 23 - (27,853)
Cash received on acquisition of additional interest 18 5,236 -
of CWLH Assets
Payment for oil and gas properties 20 (48,427) (107,500)
Payment for plant and equipment 21 (476) (516)
Payment for intangible exploration assets 19 (1,607) (1,508)
Dividends received from associate 23 8,660 3,842
Interest received 13 7,492 4,451
Net cash used in investing activities (29,122) (129,084)
2024 2023
Notes USD'000 USD'000
Financing activities
Net proceeds from issuance of shares 29 - 50,964
Shares repurchased 29 - (2,084)
Total drawdown of borrowings 38 43,000 232,000
Repayment of borrowings 38 - (75,000)
Interest on borrowings paid 38 (18,944) (5,007)
Borrowings costs paid 38 - (7,595)
Commitment fees of borrowings paid 38 (142) (658)
Repayment of lease liabilities 38 (18,985) (17,171)
Other interest and fees paid (3,322) (4,165)
Net cash generated from financing activities 1,607 171,284
Net (decrease)/increase in cash and cash equivalents (58,178) 30,075
Cash and cash equivalents at beginning of the year 153,404 123,329
Cash and cash equivalents at end of the year 28 95,226 153,404
Notes to the Consolidated Financial Statements for the year ended 31 December
2024
1. CORPORATE 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") for the year ended 31 December 2024 were authorised for issue in
accordance with a resolution of the directors on 19 May 2025.
The Group is engaged in production, development, exploration and appraisal
activities in Australia, Malaysia, Vietnam, Indonesia and was engaged in
Thailand for the year under review but disposed post year on 16 April 2025.
The Group's producing assets are in the Vulcan (Montara) basin, Carnarvon
(Stag) basin and Cossack, Wanaea, Lambert, and Hermes oil fields, located in
offshore of Western Australia, the East Piatu, East Belumut, West Belumut and
Chermingat fields, located in shallow water in offshore Peninsular Malaysia,
and were in the Sinphuhorm gas field onshore north-east Thailand. On 31 July
2024, the Group commenced commercial production at the Akatara Gas Field
located onshore Indonesia.
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 6th Floor, 60 Gracechurch Street, London, EC3V 0HR United Kingdom.
2. MATERIAL ACCOUNTING POLICY INFORMATION
BASIS OF PREPARATION
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 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 have a
reasonable expectation that the Group has adequate resources to continue in
operational existence for the foreseeable future, which represents a period of
at least 12 months from the date of approval of these financial statements
(the "Review Period").
The assessment undertaken included applying appropriate estimates of future
production, associated operating costs and committed capital expenditure.
Consideration was also given to the potential impact of increased uncertainty
and volatility caused by recent geopolitical events on global commodity
markets and modelled through downside oil price sensitivities.
As of 31 December 2024, the Group had available liquidity of US$82.8 million
in cash and cash equivalents, excluding restricted cash. As at 31 April 2025,
the Group had available liquidity of approximately US$145.6 million,
consisting of cash and cash equivalents (excluding restricted cash) of
US$115.6 million and an undrawn working capital facility of US$30 million
provided by an international bank with a 31 December 2026 maturity.
On 16 April 2025, the Group completed the sale of its 9.52% interest in the
producing Sinphuhorm gas field for a cash consideration of US$39.4 million,
with a further US$3.5 million in cash payable contingent on future license
extensions. Funds received have been used to repay a portion of the
outstanding debt under its Reserves Based Lending facility which, following
the conclusion of the March 2025 redetermination, currently has a borrowing
base 5 (#_ftn5) of US$167.0 million. The Group continues to maintain covenant
compliance of 3.5x EBITDAX to net debt under the Reserve Based Lending ("RBL")
facility with significant headroom. Based on current projections, the Group
expects to remain compliant with all financial covenants throughout the going
concern assessment period.
Capital expenditure guidance for 2025 remains at US$75 million to US$95
million, as previously disclosed, with the principal capital expenditure
relating to the Skua-11ST well side-track program. Since the balance sheet
date, Brent crude oil prices have fluctuated between US$61/bbl and US$83/bbl,
which remains within the Group's operating tolerances. The Group's financial
modeling indicates that operations remain viable within this price range.
Additionally, the Group has mitigated its exposure to oil price volatility by
implementing a hedging strategy, with approximately 1.2 million barrels of oil
hedged through the second and third quarters of 2025 at a weighted average
price of US$68.6/bbl.
The Group closely monitors its cash, funding and liquidity position, with both
near-term and longer-term cash projections and underlying assumptions reviewed
and updated regularly to reflect operational and external conditions. The
Group has conducted sensitivity analysis on its cash flow projections,
including scenarios incorporating Brent oil prices modelled at US$60/bbl
combined with additional unplanned downtime, being three separate events at
Montara, CWLH and Akatara with each event lasting one month (three months in
total), with deferral of capital expenditure and reduction in operating
expenditure through the Review Period, and includes the borrowing base, as
projected, for the six months following the redetermination in September 2025
of US$135 million and US$71 million for the six months from March 2026.
Under these stressed scenarios, together with the projected borrowing base,
the Group's liquidity position remains adequate to meet operational
requirements and debt service obligations throughout the period. In
addition, the Directors believe that there are additional courses of action
available to the Group to create further liquidity, should that be required,
including, but not limited to, the implementation of additional operating cost
efficiencies and an amendment, extension or re-financing of the existing
Reserves Based Lending facility.
The Directors have determined, at the time of approving the financial
statements, that there is reasonable expectation the Group will continue as a
going concern for the foreseeable future. Accordingly, they have prepared
these audited consolidated financial statements on a going concern basis.
Adoption of new and revised standards
New and amended IFRS standards that are effective for the current year
In the current year, the Group adopted the following amendments that are
effective from the beginning of the year and is relevant to its operations.
The adoption of these amendments has not resulted in changes to the Group's
accounting policies.
Amendments to IAS 1 Non-current liabilities with Covenants
Amendments to IAS 1 Classification of Liabilities as Current of Non-current
Amendments to IAS 1 Classification of Liabilities as Current of Non-current Deferral of
Effective Date
Amendments to IAS 7 and IFRS 7 Supplier Finance Arrangements
Amendments to IFRS 16 Lease liabilities in Sale and Leaseback
Non-current liabilities with Covenants
The Group has adopted the amendments to IAS 1, published in November 2022, for
the first time in the
current year. The amendments specify that only covenants that an entity is
required to comply with on or before the end of the reporting period affect
the entity's right to defer settlement of a liability for at least twelve
months after the reporting date (and therefore must be considered in
assessing the classification of the liability as current or non-current).
Such covenants affect whether the right exists at the end of the reporting
period, even if compliance with the covenant is assessed only after the
reporting date (e.g. a covenant based on the entity's financial position at
the reporting date that is assessed for compliance only after the reporting
date). The IASB also specifies that the right to defer settlement of a
liability for at least twelve months after the reporting date is not affected
if an entity only has to comply with a covenant after the reporting
period. However, if the entity's right to defer settlement of a liability is
subject to the entity complying with covenants within twelve months after the
reporting period, an entity discloses information that enables users
of financial statements to understand the risk of the liabilities becoming
repayable within twelve months after the reporting period. This would include
information about the covenants (including the nature of the covenants and
when the entity is required to comply with them), the carrying amount of
related liabilities and facts and circumstances, if any, that indicate that
the entity may have difficulties complying with the covenants.
New and revised IFRSs in issue but not yet effective
At the date of authorisation of these financial statements, the Group has not
applied the following amendments to IFRS standards relevant to the Group that
have been issued but are not yet effective:
Effective for annual periods beginning
Description
Amendments to IAS 21 Lack of exchangeability 1 January 2025
Amendments to IFRS 9 and IFRS 7 Contracts referencing nature-dependent
electricity
1 January 2026
Annual improvements to IFRS accounting standards - Volume 11 (IFRS 10,
IFRS 9, IFRS 1, IAS 7, IFRS 7) 1 January 2026
Amendments to IFRS 9 and IFRS 7 Amendments to the classification and 1 January 2026
measurement of financial instruments
IFRS 18 Presentation and disclosure in financial statements 1 January 2027
IFRS 19 Subsidiaries without public accountability: disclosures 1 January 2027
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 as 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. 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.
An entity is required to apply IFRS 18 for annual reporting periods beginning
on or after 1 January 2027, with earlier application permitted. IFRS 18
requires retrospective application with specific transition provisions.
The directors of the company anticipate that the application of these
amendments may have an impact on the presentation of the group's consolidated
financial statements in future periods.
BASIS OF CONSOLIDATION
The consolidated financial statements incorporate the financial statements of
the Company and all its subsidiaries made up to 31 December of each year.
The Group reassesses whether or not it controls an investee if facts and
circumstances indicate that there are changes to the elements of control.
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 the consolidated financial statements from the date the
Group gains control until the date when the Group ceases to control the
subsidiary.
Profit or loss and each component of other comprehensive income are attributed
to the owners of the Company. Total comprehensive income of subsidiaries is
attributed to the owners of the Company.
When necessary, adjustments are made to the financial statements of
subsidiaries to bring their accounting policies into line with the Group's
accounting policies.
All intragroup assets and liabilities, equity, income, expenses and cash flows
relating to transactions between members of the Group are eliminated in full
on consolidation.
BUSINESS COMBINATIONS
Acquisitions of businesses, including joint operations which are assessed to
be businesses, are accounted for using the acquisition method. The
consideration for each acquisition is measured as the aggregate of the
acquisition date fair values of assets given, liabilities incurred by the
Company to the former owners of the acquiree, and equity interests issued by
the Company in exchange for control of the acquiree. Acquisition-related costs
are recognised in profit or loss as incurred.
At the acquisition date, the identifiable assets acquired and the liabilities
assumed are recognised at their fair value, except that:
- Deferred tax assets or liabilities, and liabilities or assets
related to employee benefit arrangements are recognised 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 the replacement of an acquiree's share-based
payment awards transactions with share-based payment awards transactions of
the acquirer, in accordance with the method in IFRS 2 Share-based Payment at
the acquisition date; 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 recognised immediately in profit or loss as a bargain
purchase gain.
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 recognises 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; 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 a Group entity transacts with a joint operation in which a Group entity
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
recognised in the Group's consolidated financial statements only to the extent
of other parties' interests in the joint
operation.
When a Group entity transacts with a joint operation in which a Group entity
is a joint operator (such as a purchase of assets), the Group does not
recognise its share of the gains and losses until it resells those assets to a
third party.
Changes to the Group's interest in a PSC usually require the approval of the
appropriate regulatory authority. A change in interest is recognised 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 recognised and any funds
received or paid are included in the statement of financial position as
contractual deposits.
INVESMENT IN ASSOCIATES
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 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
recognised initially in the consolidated statement of financial position at
cost and adjusted thereafter to recognise the Group's share of the profit or
loss and other comprehensive income of the associate. When the Group's share
of losses of an associate exceeds the Group's interest in that associate
(which includes any long-term interests that, in substance, form part of the
group's net investment in the associate), the Group discontinues recognising
its share of further losses. Additional losses are recognised only to the
extent that the Group has incurred legal or constructive obligations or made
payments on behalf of the associate.
An investment in an associate is accounted for using the equity method from
the date on which the investee becomes an associate. On acquisition of the
investment in an associate, 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 recognised 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 recognised 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
is impaired, the requirements of IAS 36 are applied to determine whether it is
necessary to recognise 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 recognised 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 recognised in accordance with IAS 36 to the extent that the
recoverable amount of the investment subsequently increases.
EXPLORATION AND EVALUATION COSTS
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 capitalised 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 capitalised as E&E assets.
All such capitalised 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 recognises 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 capitalised, together with the discounted value of
estimated future costs of decommissioning obligations. Workover expenses are
recognised in profit or loss in the period in which they are incurred, unless
it generates additional reserves or prolongs the economic life of the well, in
which case it is capitalised. When components of oil and gas properties are
replaced, disposed of, or no longer in use, they are derecognised.
Depletion and amortisation 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 in 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 capitalised as part of cost of inventories and
recognised 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 capitalised 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 recognised as a change in the asset restoration liability
and related capitalised asset restoration cost within oil and gas properties.
The Malaysian and Indonesian regulators require upstream oil and gas companies
to contribute to an abandonment cess fund, including making periodic cess
payments, throughout the production life of the oil or gas field. The
Malaysian cess payment amount is assessed based on the estimated future
decommissioning expenditures on oil and gas facilities, excluding wells. The
Indonesian cess payment amount is assessed based on the estimated future
decommissioning expenditures of all facilities. For operated licenses, the
cess payment paid is classified as non-current receivables as the cess payment
paid is reclaimable by the Group in the future following the commencement of
decommissioning activities. For non-operated licenses, the cess payment paid
reduces the asset restoration liability.
An abandonment trust fund was set up 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 payment paid into the trust fund is
classified as non-current receivables as the amount is reclaimable by the
Group in the future following the commencement of decommissioning activities.
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.
Capitalised asset restoration costs are depleted using the units of production
method (see above accounting policy).
BORROWING COSTS
Borrowing costs consist of interest and other costs that an entity incurs in
connection with the borrowing of funds.
Borrowing costs directly attributable to the acquisition, construction or
production of qualifying assets, which are assets that necessarily take a
substantial period of time to get ready for their intended use or sale, are
added to the cost of those assets, until such time as the assets are
substantially ready for their intended use or sale. All other borrowing costs
are recognised in the profit or loss in the period in which they are incurred.
PLANT AND EQUIPMENT
Plant and equipment is stated at cost less accumulated depreciation and any
recognised impairment loss.
Depreciation is recognised so as to write off the cost of assets less their
residual values using the straight-line method over their useful lives, on the
following:
- 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.
Right-of-use assets are depreciated over the shorter period of the lease term
and the useful life of the underlying asset. If the ownership of the
underlying asset in a lease is transferred, 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.
An item of plant and equipment is derecognised upon disposal or when no future
economic benefits are expected to arise from the continued use of asset. Any
gain or loss arising on the disposal or retirement of an item of plant and
equipment is determined as the difference between the sales proceeds and the
carrying amount of the asset and is recognised in profit or loss.
IMPAIRMENT OF OIL AND GAS PROPERTIES, PLANT AND EQUIPMENT, RIGHT-OF-USE ASSETS
AND INTANGIBLE EXPLORATION ASSETS
At each reporting period, the Group reviews the carrying amounts of its oil
and gas properties, plant and equipment, right-of-use assets and intangible
assets, to determine whether there is any indication that those assets have
suffered an impairment loss. If any indication exists, the recoverable
amount of the asset is estimated in order to determine the extent of the
impairment loss (if any). 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 pre-tax 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 recognised immediately 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 recognised for the asset (or cash-generating unit) in prior years. A
reversal of an impairment loss is recognised immediately in profit or loss.
INVENTORIES
Inventories are valued at the lower of cost and net realisable 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 realisable 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 realisable value, a write-down is recognised.
Provision for slow moving materials and spares are recognised in the "other
expenses" (Note 10) line item in profit or loss as they are non-trade in
nature.
Under/Overlift
Offtake arrangements for oil and gas produced in certain of the Group's
jointly owned operations may result in the Group not receiving and selling its
precise share of the overall production in a period. The resulting imbalance
between the Group's cumulative entitlement and share of cumulative production
less stock gives rise to an underlift or overlift.
Entitlement imbalances in under/overlift positions and the movements in
inventory are included in production costs (Note 5). An overlift liability
is measured on the basis of the cost of production and represents a provision
for production costs attributable to the volumes sold in excess of
entitlement. The underlift asset is measured at the lower of cost and net
realisable value, consistent with IAS 2, to represent a right to additional
physical inventory. An underlift of production from a field is included in
current receivables and an overlift of production from a field is included in
current liabilities.
FINANCIAL INSTRUMENTS
Financial assets and financial liabilities are recognised in the Group's
consolidated 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
measured at fair value through the profit or loss) 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 measured at fair value through profit or loss are
recognised immediately in profit or loss.
Financial assets
All financial assets are recognised and derecognised on a trade date basis,
where the purchases or sales of financial assets is under a contract whose
terms require delivery of assets within the time frame established by the
market concerned.
All recognised financial assets are measured subsequently in their entirety,
at either amortised 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 amortised 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 fair value
through profit or loss ("FVTPL").
Amortised cost and effective interest method
The effective interest method is a method of calculating the amortised cost of
a financial asset and of allocating interest income over the relevant period.
For financial assets, the effective interest rate is the rate that exactly
discounts estimated future cash receipts (including all fees 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 financial asset, or, where appropriate, a shorter period,
to the gross carrying amount of the financial instrument on initial
recognition.
The amortised 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 amortisation 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
amortised cost of a financial asset before adjusting for any loss allowance.
Interest income is recognised using the effective interest method for
financial assets measured subsequently at amortised cost and at fair value
through other comprehensive income. 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 recognised by applying the effective interest
rate to the amortised 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
recognised by applying the effective interest rate to the gross carrying
amount of the financial asset.
Interest income is recognised in profit or loss and is included in "other
income" (Note 13) line item.
Impairment of financial assets
The Group recognises a loss allowance for expected credit losses on
investments in debt instruments that are measured at amortised 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 recognises 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 recognises 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.
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 as 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, based on consideration of various external sources of actual and
forecast economic information plus environment impacts 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 amortised 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.
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 low credit risk at the reporting
date. A financial instrument is determined to have low credit risk if i) the
financial instrument has a low risk of default, ii) the borrower has a strong
capacity to meet its contractual cash flow obligations in the near term and
iii) 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.
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 receivables 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).
Write-off policy
The Group writes off a financial asset when there is information indicating
that the counterparty is in severe financial difficulty and there is no
realistic prospect of recovery.
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, together with any
additional amounts expected to be drawn down in the future by the 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.
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.
Derecognition of financial assets
The Group derecognises 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 recognises its retained interest in the asset and an
associated liability for amounts it may have to pay. If the Group retains
substantially all of the risks and rewards of ownership of a transferred
financial asset, the Group continues to recognise the financial asset and also
recognises a collaterialised borrowing for the proceeds received.
On derecognition of a financial asset measured at amortised cost, the
difference between the asset's carrying amount and the sum of the
consideration received and receivables, is recognised in the profit or loss.
Financial liabilities
All financial liabilities are measured subsequently at amortised 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, 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) designated as at FVTPL.
A financial liability other than a contingent consideration of an acquirer in
a business combination may be designated as at FVTPL upon initial recognition
if:
- 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 classified as at FVTPL are measured at fair value, with
any gains or losses arising on changes in fair value recognised 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 recognised in profit or
loss incorporates any interest paid on the financial liability and is included
in either "other financial gains" (Note 15) or "finance costs" (Note 14) line
item in profit or loss.
Financial liabilities measured subsequently at amortised cost
The effective interest method is a method of calculating the amortised 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 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 amortised cost of a financial
liability.
Derecognition of financial liabilities
The Group derecognises 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 derecognised, and the
consideration paid and payable, is recognised in profit or loss.
Equity instruments
Ordinary shares issued by the Company are classified as equity and recorded at
the par value in the share capital account and the fair value of the proceeds
received recorded in the share premium account.
Derivative financial instruments
The Group enters into a variety of derivative financial instruments to manage
its exposure to commodity price and foreign exchange risks.
Derivatives are initially recognised at fair value. The resulting gain or loss
is recognised in profit or loss immediately unless the derivative is
designated and effective as a hedging instrument, in which case 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 recognised as a financial asset
whereas a derivative with a negative fair value is recognised 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. 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 realised 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 recognised asset or liability, or a component of a
recognised 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, the Group documents whether the hedging
instrument is 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 are 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 amortisation. Those
reclassified amounts are recognised 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 recognised 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 40 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 34.
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 recognised in other comprehensive income, 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 recognised immediately in
profit or loss in either "other financial gains" (Note 15) or "finance costs"
(Note 14) line item.
Amounts previously recognised in other comprehensive income are reclassified
to profit or loss in the periods when the hedged item affects profit or loss,
in the same line as the recognised hedged item. 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. The discontinuation
is accounted for prospectively. Any gain or loss recognised in other
comprehensive, 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 cash flow hedge
reserve is reclassified immediately to profit or loss.
FAIR VALUE ESTIMATION OF FINANCIAL ASSETS AND LIABILITIES
The fair value of current financial assets and liabilities carried at
amortised cost, approximate their carrying amounts, as the effect of
discounting is immaterial.
SHARE-BASED PAYMENTS
Share-based incentive arrangements are provided to employees, allowing them to
acquire shares of the Company. The fair value of equity-settled options
granted is recognised 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 recognised 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 recognised 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 recognised in profit or loss for the year.
LEASES
The Group as lessee
The Group assesses whether a contract is or contains a lease, at inception of
the contract. The Group recognises 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 leases of low value assets (such as personal computers,
small items of office furniture and telephones). For these leases, the Group
recognises the lease payments as an operating expense on a straight-line basis
over the term of the lease, unless another systematic basis is more
representative of the time pattern in which economic benefits from the leased
assets are consumed.
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. Lease payments included
in the measurement of the lease liability comprise fixed lease payments
(including in substance fixed payments).
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 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 recognised 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. 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.
PROVISIONS
Provisions are recognised when the Group has a present obligation, legal or
constructive, as a result of a past event, and it is probable that the Group
will be required to settle the obligation, and a reliable estimate can be made
of the amount of the obligation.
The amount recognised as a provision is the best estimate of the consideration
required to settle the present obligation at the end of the reporting period,
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, and 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 35.
RETIREMENT BENEFIT OBLIGATIONS
Payments to defined contribution retirement benefit plans are charged as an
expense as and when employees have tendered the services entitling them to the
contributions. Payments made to state managed retirement benefit schemes, such
as Malaysia's Employees Provident Fund, are dealt with 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.
REVENUE
Revenue from contracts with customers is recognised 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 recognises 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 recognised hedged item, in this case, revenue.
Revenue from the production of oil, liquified petroleum gas ("LPG"),
condensate and and gas, in which the Group has an interest with other
producers, is recognised based on the Group's working interest and the terms
of the relevant production sharing contracts.
Liquids production revenue which includes oil, LGP and condensate are
recognised 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 recognised is based on
the agreed transaction price and volumes delivered. In line with the
aforementioned, revenue is recognised 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 recognised at a point in time when deliveries of
the gas are transferred to the customer.
A receivable is recognised once transfer has occurred, as this represents the
point in time at which the right to consideration becomes unconditional, and
only the passage of time is required before the payment is due.
INCOME TAX
Income tax expense represents the sum of the current tax and deferred tax.
Current tax
The current tax is based on taxable profit or loss for the year which is
calculated using tax rates (and tax laws) that have been enacted or
substantively enacted, in countries where the Company and its subsidiaries
operate, by the end of the reporting period.
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 recognised on temporary differences between the carrying
amounts of assets and liabilities in the financial statements, and the
corresponding tax bases. Deferred tax liabilities are generally recognised for
all taxable temporary differences and deferred tax assets are recognised to
the extent that it is probable that taxable profits will be available, against
which deductible temporary differences can be utilised. Such deferred tax
assets and liabilities are not utilised if the temporary difference arises
from goodwill or 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. Deferred tax is
recognised for taxable temporary differences arising on investments in
subsidiaries, 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, are only recognised to the extent that it is probable
that there will be sufficient taxable profits against which to utilise. The
carrying amount of deferred tax assets is reviewed at the end of each
reporting period 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 realised, based on the tax
rates (and tax laws) that have been enacted or substantively enacted, by the
end of the reporting period. 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.
Deferred tax assets and liabilities are offset when there is a legally
enforceable right to set off 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 recognised as an expense or income in profit or
loss, except when they relate to items credited or debited outside profit or
loss (either in other comprehensive income or directly in equity), in which
case the tax is also recognised outside profit or loss (either in other
comprehensive income or directly in equity, respectively).
Other taxes
Revenue, expenses, assets, and liabilities are recognised 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
recognised 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.
CASH AND BANK BALANCES
Cash and bank balances comprise cash in hand and at bank, and other short-term
deposits held by the Group with maturities of less than three months.
Restricted cash and cash equivalents balances are those which meet the
definition of cash and cash equivalents but are not available for use by the
Group.
3. CRITICAL ACCOUNTING JUDGEMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY
In the application of the Group's accounting policies, Directors are required
to make judgments, estimates and assumptions about the carrying amounts of
assets and liabilities. 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 recognised 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.
Most significant accounting judgments
The following are the judgements, apart from those involving estimates (see
below) that the Directors have made in the process of applying the Group's
accounting policies that have the most significant effect on the amounts
recognised in the financial statements.
a) Acquisitions, divestitures and/or assignment of interests
The Group accounts for acquisitions and divestitures by considering if the
acquired or transferred interest relates to that of an asset, or of a business
as defined in IFRS 3 Business Combinations paragraph B7, B8 and Appendix A, in
so far as those principles do not conflict with the guidance in IFRS 11 Joint
Arrangements paragraph 21A. Accordingly, the Group considers if there is the
existence of business elements as defined in IFRS 3 (e.g., inputs and
substantive processes), or a group of assets that includes inputs and
substantial processes that together significantly contribute to the ability to
create outputs and providing a return to investors or other economic
benefits. The justifications for this assessment on the acquisition of the
CWLH Assets have been set out in Note 18.
b) 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) in each
reporting period 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. For example, individual oil and gas properties may form separate
CGUs whilst certain oil and gas properties with shared infrastructure may be
grouped together to form a single CGU. Alternative groupings of assets or
CGUs may result in a different outcome from impairment testing. See Note 12
for details on how these groupings have been determined in relation to the
impairment testing of oil and gas properties.
c) 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 to 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 end of the reporting period, that 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 amortisation charged
to the statement of profit or loss and other comprehensive income, and the
calculation of inventory. Based on the analysis performed, a 5% decrease in
the reserves estimates would result in an pre-impairment charge of US$40.4
million and a 5% increase in the reserves estimates would result in an
increase in the headroom above impairment. The Directors consider 5%
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 post-tax estimated future cash flows are prepared based on
estimated reserves, 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 post-tax 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 recognises 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). The Group's
current oil price assumption for internal planning purposes is broadly in line
with the IEA's STEPS case, which in turn is underpinned by climate policies
and targets already announced by governments. 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 predicts global oil demand will fall
from 97 mb/d in 2022 to 78 mb/d by 2030 and 24/mb/d by 2050. Prices fall to
US$40/bbl in 2030 and trend lower thereafter. The oil price differential
between STEPS 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 analyses
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 forecasted price assumptions are US$77.1/bbl in 2025, US$76.7/bbl in 2026,
US$79.4/bbl in 2027, US$80.8/bbl in 2028 and an average of US$82.5/bbl from
2029 onwards. The Directors are of the view that these price assumptions are
aligned with the Group's latest internal forecasts, 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 impairment charge of US$100.7 million and a 10% price
increase in isolation would increase the current headroom without any negative
impacts.
The oil price sensitivity analyses above do not, however, represent the
Directors' best estimate of any impairments that might be recognised 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 5% (2023: 5%) change to the post-tax
discount rate used of 11.1% in Australia (Stag, Montara & CWLH), 12.8% in
Malaysia (PenMal) and 14.0% in Indonesia (Akatara), (2023 Group: 10.50%) for
impairment testing of oil and gas properties, and concluded that a 5% increase
in the post-tax discount rate would result to an impairment charge of US$12.1
million and a 5% decrease in the post-tax discount rate would increase the
headroom without any negative impact.
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 below. The oil prices under the Net Zero
Emissions by 2050 Scenario for each asset are as follows:
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 >>2035
Brent 74.10 71.70 74.20 66.90 59.60 52.30 51.60 51.00 50.30 49.60 47.23*
*From 2035 this represents the average for the period 2035-2040.
Based on the analysis performed, the reduction in operating cash flows under
the Net Zero Emissions by 2050 Scenario would result to in a pre-tax
impairment charge of US$251.1 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 35 to the
financial statements.
Sensitivity analyses
Sensitivities have been run on the discount rate assumption, with a 1% change
being considered a reasonable possible change for the purposes of sensitivity
analysis. A 1% reduction in discount rate would increase the liability by
US$49.8 million and a 1% increase in discount rate would decrease the
liability by US$45.0 million. A 1% increase in the inflation rate would
increase the liability by US$49.9 million and a 1% decrease in inflation rate
would decrease the liability by US$46.8 million. A 10% increase in current
estimated costs would increase the liability by US$61.6 million and a 10%
decrease in current estimated costs would decrease the liability by US$61.3
million. A one year deferral to the estimated decommissioning year of each
asset as disclosed in Note 35 would decrease the liability by US$11.5 million
and an acceleration of one year to the estimated decommissioning year as
disclosed in Note 35 would increase the liability by US$8.0 million. The
Directors consider the 1% movement to the discount rate and inflation rate,
10% to the current estimated costs and one year movement to the estimated
decommissioning year a reasonable assumption based on the historical
adjustments to the risk-free rates, base decommissioning costs and estimated
decommissioning year.
d) Deferred tax assets
Deferred tax assets are recognised for all unutilised 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
utilised. Significant management judgement is required to determine the amount
of deferred tax assets that can be recognised, based on the likely timing and
level of future taxable profits together with future tax planning strategies.
If the Group were able to recognise all unrecognised deferred tax assets, the
profit would increase by US$10.9 million. The amount of recognised are
disclosed in Note 25.
4. REVENUE
The Group presently derives its revenue from contracts with customers for the
sale of hydrocarbon products including oil, gas, condensate and LPG.
In line with the revenue accounting policies set out in Note 2, all revenue is
recognised at a point in time.
2024 2023
USD'000 USD'000
Liquids revenue 405,964 317,469
Hedging loss (Note 34 and Note 40) (27,417) (10,322)
378,547 307,147
Gas revenue 7,962 2,053
LPG revenue 4,313 -
Condensate revenue 4,214 -
395,036 309,200
As required under the RBL as disclosed in note 36, the Group entered into
commodity swap contracts to hedge approximately 50% of its forecasted planned
liquids production from October 2023 to September 2025. The commodity swap
contracts were measured using hedge accounting. See Note 40 for the details of
the commodity swap contracts.
On 31 July 2024, the Group successfully commenced operations of the Akatara
Gas Processing Facility ("Akatara Facility") producing gas, liquefied
petroleum gas ("LPG"), and condensate.
5. PRODUCTION COSTS
2024 2023
USD'000 USD'000
Operating costs 129,078 114,779
Workovers 20,797 17,562
Logistics 26,928 34,109
Repairs and maintenance 70,304 55,572
Tariffs and transportation costs 8,451 7,502
Decommissioning expenses - 12,545
Underlift and overlift and crude inventories movement 21,411 (9,297)
276,969 232,772
Operating costs predominately consist of offshore manpower costs of US$30.6
million (2023: US$26.0 million), chemicals, services, supplies and other
production related costs for a total of US$40.0 million (2023: US$49.3
million), Malaysian supplementary payments totalled US$6.8 million (2023:
US$10.5 million), CWLH Asset royalties of US$6.7 million (2023: US$3.5
million), Montara royalties of US$2.5 million (2023: US$1.7 million),
insurance of US$5.3 million (2023: US$4.9 million) and non-operated assets
production costs of US$31.3 million (2023: US$16.0 million). The Malaysian
supplementary payments are payable under the terms of PSCs based on the
Group's entitlement to profit from oil and gas.
The crude inventories movements represent the net movement of crude
inventories at year end against beginning of the year which represent the
production cost excluding the depletion expenses portion as disclosed in Note
6. The underlift, overlift and crude inventories movements resulted in and
expenses of US$21.4 million (2023: credit of US$9.3 million charge), which
mostly related to US$40.6 million of expense subsequent to lifting associated
with the acquisition of the second tranche of the CWLH Asset. 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 on Note 18. The inventory was sold in
March 2024. At year end, CWLH is in underlift position of 386,451 bbls and
accordingly has recognised a credit of US$18.1 million.
Workovers in 2024 and 2023 were recurring in nature. The Group carried out a
higher number of workovers at Stag in 2024 in comparison of 2023.
Repairs and maintenance in current year include rectification costs of the
cranes and platform of AAKBNLP asset at PenMal, subsea maintenance at Montara
and fabric maintenance costs at Stag. In 2023, the costs included storage tank
repairs, FPSO ("Floating, Production Storage and Offloading") maintenance and
fabric maintenance costs at both Montara and Stag.
In 2023, the Group incurred US$12.5 million in decommissioning expenses
related to its non-operated interest in the FPSO at the PNLP Asset before the
previous operator departure.
6. DEPLETION, DEPRECIATION AND AMORTISATION ("DD&A")
2024 2023
USD'000 USD'000
Depletion and amortisation (Note 20) 77,187 64,575
Depreciation of:
Plant and equipment (Note 21) 555 494
Right-of-use assets (Note 22) 16,195 15,251
Crude inventories movement (2,530) (4,179)
91,407 76,141
The crude inventories movement represents a reversal of depletion expense
recognised 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.
7. ADMINISTRATIVE STAFF COSTS
2024 2023
USD'000 USD'000
Wages, salaries and fees 28,985 24,729
Staff benefits in kind 5,031 4,702
Share-based compensation (Note 32) 407 766
34,423 30,197
The compensations of Directors and key management personnel are included in
the above and disclosed separately in Notes 9 and 47, respectively.
8. STAFF NUMBERS AND COSTS
The average number of employees (including Executive Directors) was:
2024 2023
Number Number
Production 159 162
Technical 254 238
Management 9 9
422 409
Staff costs are split between production costs (Note 5) for offshore personnel
and administrative staff costs (Note 7) for onshore personnel. 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:
2024 2023
Reclassified*
USD'000 USD'000
Wages and salaries 51,750 44,343
Fees 701 767
Staff benefits in kind 3,697 3,270
Social security costs 233 180
Defined contribution pension costs 3,251 3,149
Share-based compensation (Note 32) 407 766
60,039 52,475
Contractors and consultants costs 5,011 3,704
65,050 56,179
*In 2024, management has applied a new categorisation for fees and benefits in
kind compared to the prior year's disclosure. As a result, prior year figures
for wages and salaries, social security costs, defined contribution pension
costs, and contractor and consultant costs have been reclassified accordingly.
9. DIRECTORS' REMUNERATION AND TRANSACTIONS
2024 2023
USD'000 USD'000
Directors' remuneration
Salaries, fees, bonuses and benefits in kind 2,620 2,496
Amounts receivable under long term incentive plans 233 300
Money purchase pension contributions 87 102
Compensation for loss of office 2,464((a)) -
5,404 2,898
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 4 2
incentive scheme
( )
((a)) Compensation for loss of office amounting to US$2.3 million, including
US$0.2 million of payroll tax for A. Paul Blakeley.
The Non-Executive Directors were not granted any options/shares under the
Company's long term incentive plans.
For further details and details of remuneration of the highest paid director,
please refer to Note 47.
10. OTHER EXPENSES AND ALLOWANCE FOR EXPECTED CREDIT LOSSSES
2024 2023
USD'000 USD'000
Corporate costs 13,962 14,179
Allowance for slow moving inventories 1,670 655
Assets written off 1,775 5,114
Net foreign exchange loss 2,008 1,728
Other expenses 4,444 1,165
23,859 22,841
2024 2023
USD'000 USD'000
Allowance for expected credit losses (Note 27) 457 -
457 -
Corporate costs include recurring general and administration expenses such as
professional fees, office and travelling costs of US$12.5 million (2023:
US$10.5 million) and non-recurring costs such as business development costs of
US$0.9 million (2023: US$2.2 million), professional fees in relation to
internal reorganisation of US$0.1 million (2023: US$0.8 million), equity
fundraising of US$Nil (2023: US$0.4 million) and external funding sourcing of
US$0.5 million (2023: US$0.2 million).
Assets written off in 2024 represent the derecognition of US$1.4 million of
Montara non-depletable oil and gas properties following capitalisation of
replacement parts and US$0.4 million of obsolete materials and spares. In
2023, write-offs included US$3.1 million for Montara non-depletable oil and
gas properties following the cancellation of the Skua-12 well development
capital project, as well as US$2.0 million for obsolete materials and spares.
Other expenses mainly consist of US$1.5 million of expenses of dividend based
royalties from Sinphuhorm gas field and another US$1.3 million related to
withholding taxes expenses.
11. AUDITOR'S REMUNERATION
The analysis of the auditor's remuneration is as follows:
2024 2023
USD'000 USD'000
Fees payable to the Company's auditor for the audit of the parent 668 600
company and Group's consolidated financial statements
Audit fees of the subsidiaries 519 417
1,187 1,017
No fee was paid to the Group's auditor for non-audit services for either the
Group or the Company in 2023 or 2024.
12. IMPAIRMENT OF ASSETS
2024 2023
USD'000 USD'000
Impairment of oil and gas properties (Note 20) - 29,681
The impairment expense in 2023 consists of US$17.4 million for the impairment
of Stag's oil and gas properties, which is treated as a single cash-generating
unit. The impairment was made following the annual impairment assessment
performed by the Directors which identified that the VIU ("Value in Use') of
the operating asset, determined based on the post-tax discount rate used of
10.5%, was lower than the carrying amount. The impairment was made to reduce
the carrying amount of Stag's oil and gas properties to its recoverable amount
of US$95.8 million. The key assumptions used in determining the VIU are
disclosed Note 3(b). The impairment was made in relation to the producing
asset of the Group located in Australia as disclosed in Note 43. There is no
impairment noted in 2024.
Additionally in 2023, the Group also provided impairment of US$12.3 million
associated with the adjustment to the ARO estimates for the PNLP Assets (Note
35) that underwent retendering during the year after ceasing production in
2022, following the class suspension of the FPSO. The revision of ARO
estimates reflects the change in assumptions used for the estimation of the
decommissioning costs.
13. OTHER INCOME
2024 2023
USD'000 USD'000
Interest income 7,492 4,451
Reversal of provisions:
Lemang PSC contingent payments (Note 35) - 7,653
Asset restoration obligations (Note 20 and Note 35) 13,824 -
Others (Note 35) 1,112 -
Net foreign exchange gain 921 322
Rental income 5,731 6,375
Sundry income 534 54
29,614 18,855
14. FINANCE COSTS
2024 2023
USD'000 USD'000
Interest expense:
Lease liabilities 2,465 2,771
Standby working facility (Note 36) 1,483 953
RBL facility (Note 36) 16,428 8,089*
Others 178 138*
Accretion expense for:
Asset restoration obligations (Note 35) 22,544 20,201
Non-current Lemang PSC VAT receivables 180 1,182
Fair value loss on warrants (Note 41) - 3,469
Upfront fees on financing facilities 867 2,656
Changes in fair value of:
Lemang PSC contingent payments (Note 35) 53 868
CWLH Assets contingent payment (Note 35) - 60
RBL commitment fees (Note 36) 142 349
Fair value loss on derivative liability (Note 40) - 73
Other finance costs 794 1,020
45,134 41,829
* We have reclassified the categorisation of interest expenses of US$2.7
million and RBL accretion expenses of US$5.5 million in 2023 to interest
expenses on RBL facility of US$8.1 million and interest expenses on others of
US$0.1 million.
15. OTHER FINANCIAL GAINS
2024 2023
USD'000 USD'000
Fair value gain on warrants (Note 41) 2,538 -
Fair value gain on derivative liability 73 -
2,611 -
16. INCOME TAX EXPENSE/(CREDIT)
2024 2023
USD'000 USD'000
Current tax
Corporate tax charge/(credit) 1,066 (3,403)
(Over)/underprovision in prior years (468) 2,051
598 (1,352)
Australian petroleum resource rent tax ("PRRT") (1,700) 1,735
Malaysian petroleum income tax ("PITA") 8,275 10,377
7,173 10,760
Deferred tax
Corporate tax (1,548) (20,138)
Underprovision of deferred tax in prior years (361) -
(1,909) (20,138)
PRRT (10,031) (4,269)
PITA 5,473 2,155
(6,467) (22,252)
706 (11,492)
On 23 May 2023, the International Accounting Standards Board issued
International Tax Reform - Pillar Two Model Rules - Amendments to IAS 12 which
clarify that IAS 12 applies to income taxes arising from tax law enacted or
substantively enacted to implement the Pillar Two model rules published by the
Organisation for Economic Co-operation and Development ("OECD"), including
tax law that implements Qualified Domestic Minimum Top-up Taxes. The Group has
adopted these amendments. However, they are not yet applicable for the
current reporting year as the Group's consolidated revenue is currently below
the threshold of €750.0 million.
Jadestone Energy plc's tax domicile is Singapore and is subjected to
Singapore's domestic corporate tax rate of 17%. Subsidiaries are resident
for tax purposes in the territories in which they operate.
The Australian corporate income tax rate is applied at 30% of Australian
corporate taxable income. PRRT is calculated at 40% of sales revenue less
certain permitted deductions and is tax deductible for Australian corporate
income tax purposes.
As at year end, Montara and the CWLH Assets have US$4.1 billion (2023: US$3.8
billion) and US$802.4 million (2023: US$493.4 million) of unutilised carried
forward PRRT credits, respectively. Based on Directors' latest forecasts,
the historic accumulated PRRT net losses are larger than cumulative future
expected PRRT taxable profits. Accordingly, Montara and the CWLH Assets are
not anticipated to incur any PRRT expense in the future of the asset.
During the year, Stag recorded a net PRRT credit of US$11.7 million (2023:
expense of US$2.5 million).
The Malaysian corporate income tax is applied at 24% on non-petroleum taxable
income. PITA is calculated at 38% of sales revenue less certain permitted
deductions and is tax deductible for Malaysian corporate income tax purposes.
PenMal Assets recorded PITA expense of US$13.7 million during the year (2023:
US$12.5 million).
The Indonesia corporate income tax rate is applied at 30% of Indonesia
corporate taxable income. Corporate and Dividend Tax ("C&D") is calculated
at 20% of sales revenue less certain permitted deductions and is tax
deductible for Indonesia corporate income tax purposes. There is no tax
expense during the year for Indonesia tax due to the Lemang asset as it is not
in a taxable income position.
The tax recoverable of US$13.8million (2023: US$4.1 million) as at year end
includes a PITA receivable of US$3.9 million (2023: US$3.9 million) which
arose from pre-economic effective date of the PenMal Assets acquisition which
will be payable to SapuraOMV following the receipt of a tax refund. The
Group has recognised the payable to SapuraOMV as at year end.
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:
2024 2023
USD'000 USD'000
Loss before tax (43,435) (102,766)
Tax calculated at the domestic tax rates applicable to the profit/loss in the (10,323) (27,543)
respective countries (Australia 30%, Malaysia 24% & 38%, Canada 27%,
Singapore 17% and Indonesia 30%)
Effects of non-deductible expenses 839 4,003
Income not subject to tax (1,897) -
Effect of PRRT/PITA tax expense 6,575 12,112
Deferred PRRT/PITA tax (credit)/expense (4,558) (2,115)
Deferred tax assets not recognised 10,899 -
(Over)/underprovision of current tax in prior years (468) 2,051
Underprovision of deferred tax in prior years (361) -
Tax expense/(credit) for the year 706 (11,492)
Deferred tax assets amounting of US$10.9 million (2023: US$Nil) have not been
recognised in respect of these 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. Unrecognised deferred tax assets during the year amount to US$10.9
million.
In addition to the amount charged to the profit or loss, the following amounts
relating to tax have been recognised in other comprehensive income.
2024 2023
USD'000 USD'000
Other comprehensive income - deferred tax
Income tax expense/(credit) related to carrying amount of hedged item 3,770 (6,056)
17. LOSS PER ORDINARY SHARE
The calculation of the basic and diluted loss per share is based on the
following data:
2024 2023
USD'000 USD'000
Loss for the purposes of basic and diluted per share, being the net loss for (44,141) (91,274)
the year attributable to equity holders of the Company
2024 2023
Number Number
Weighted average number of ordinary shares for the purposes of 540,848,891 499,480,437
basic EPS
Weighted average number of ordinary shares for the purposes of 540,848,891 499,480,437
dilutive EPS
In 2024, 47,139 (2023: 2,493,421) of weighted average potentially dilutive
ordinary shares available for exercise from in the money vested options,
associated with share options were excluded from the calculation of diluted
EPS, as they are anti-dilutive in view of the loss for the year.
In 2024, 53,106 (2023: 79,326) of weighted average contingently issuable
shares associated under the Company's performance share plan based on the
respective performance measures up to year end were excluded from the
calculation of diluted EPS, as they are anti-dilutive in view of the loss for
the year.
In 2024, 293,655 (2023: 344,225) of weighted average contingently issuable
shares under the Company's restricted share plan were excluded from the
calculation of diluted EPS, as they are anti-dilutive in view of the loss for
the year.
In 2024, 30,000,000 (2023: 17,095,890) of weighted average contingently
issuable shares under the Company's warrants instrument were excluded from the
calculation of diluted EPS, as they are anti-dilutive in view of the loss for
the year.
Loss per share (US$) 2024 2023
- Basic and diluted (0.08) (0.18)
18. ACQUISITIONS
18.1 ACQUISTION 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:
USD'000
Asset purchase price 9,000
Closing statement adjustments 6 (14,236)
Net cash receipts from the acquisition (5,236)
The Group considers that the purchase consideration and the transaction terms
to be reflective of fair value for the following reasons:
· Open and unrestricted market: there were no restrictions in place
preventing other potential buyers from negotiating with seller during the
sales process period and there were a number of other interested parties in
the formal sale process;
· Knowledgeable, willing and non-distressed parties: both the Group
and Seller are experienced oil and gas operators under no duress to buy or
sell. The process was conducted over several months which gave both parties
sufficient time to conduct due diligence and prepare analysis to support the
transaction; and
· Arm's length nature: the Group is not a related party to Seller.
Both parties had engaged their own professional advisors. There is no reason
to conclude that the transaction was not transacted at arm's length.
d. Assets acquired and liabilities assumed at the date of acquisition
During the year, the Group has completed the purchase price assessment ("PPA")
to determine the fair value of the net assets acquired within 12 months from
the acquisition date. The fair value of the identifiable assets and
liabilities have been reflected in the financial statements as at 31 December
2024.
Below are the effects of final PPA adjustments in accordance with IFRS 3:
PPA
USD'000
Asset
Non-current asset
Oil and gas properties (Note 20) 118
Deferred tax assets 19,763
Current asset
Amount due from joint arrangement partner 194
Trade and other receivables 40,602*
60,677
PPA
USD'000
Liabilities
Non-current liabilities
Provision for asset restoration obligations (Note 35) 65,881
Deferred tax liabilities 32
65,913
Net identifiable liabilities assumed (5,236)
* Trade and other receivables consisted of a gross underlift position of
530,484 bbls acquired by the Group, with a fair value of US$40.6 million,
measured at the market price as at closing based on the February 2024 market
value of US$86.27/bbl, less royalties and selling fees. The underlift position
was recognised as an expense in production cost, following a lifting which
occurred in March 2024.
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 recognised 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 recognised at fair value of US$40.6
million. This amount is subsequently recognised 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.
18.2 ACQUISITION OF THE REMAINING 50% INTEREST IN THE PNLP ASSETS
a. Effective date and acquisition date
On 14 April 2023, Jadestone assumed operatorship of the PNLP Assets following
the decision of the previous operator to withdraw from the licenses. As part
of the takeover, the previous operator paid the Group a sum representing its
share of future wells preservation activities and decommissioning costs. The
effective date of the takeover is 14 April 2023.
b. Asset acquisition
The acquisition of the remaining 50% interest in the PNLP Assets is an asset
acquisition as the PNLP Assets does not come with an organised workforce due
to the PNLP Assets being shut-in since February 2022 as a result of the class
suspension of the Bunga Kertas FPSO which served the PNLP Assets.
Additionally, the Group does not take over any process in the form of a
system, protocol or standards to contribute to the creation of outputs.
c. Assets acquired and liabilities assumed at the date of acquisition
The value of the identifiable assets and liabilities, acquired and assumed as
at the date of acquisition, were allocated on the basis of their relative fair
values as follows:
USD'000
Asset
Non-current asset
Other receivables (Note 27) 28,176
28,176
Liabilities
Non-current liabilities
Provision for asset restoration obligations (Note 35) 48,430
48,430
Net identifiable liabilities assumed (20,254)
19. INTANGIBLE EXPLORATION ASSETS
USD'000
Cost
As at 1 January 2023 77,928
Additions 1,636((b))
As at 31 December 2023 79,564
Additions 11,759((a)(b))
As at 31 December 2024 91,323
Impairment
As at 1 January 2023, 31 December 2023 and 31 December 2024 -
Carrying amount
As at 31 December 2023 79,564
As at 31 December 2024 91,323
((a)) Additions during the year includes of 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 35.
((b)) For the purpose of the consolidated statement of cash flows, current
year expenditure on intangible exploration assets of US$10.2 million remained
unpaid as at 31 December 2024 (2023: US$0.1 million).
20. OIL AND GAS PROPERTIES
Production assets Development assets
Total
USD'000 USD'000 USD'000
Cost
As at 1 January 2023 693,458 36,935 730,393
Changes in asset restoration obligations (Note 35) 3,133 4,017 7,150((a))
Additions 32,058 81,672 113,730((b))
Transfer of 50% interest in PNLP Assets 48,430 - 48,430
Written off (3,067) - (3,067)
As at 31 December 2023 774,012 122,624 896,636
Changes in asset restoration obligations (Note 35) (20,025) 1,330 (18,695)((a))
Additions 19,281 42,943 62,224((b))
Acquisition of additional interest of CWLH Assets
(Note 18) 118 - 118
Written off (2,965) - (2,965)
Reclassification 166,897((c)) (166,897)((c)) -
As at 31 December 2024 937,318 - 937,318
Accumulated depletion, amortisation and
impairment
As at 1 January 2023 296,748 - 296,748
Charge for the year (Note 6) 64,575 - 64,575
Impairment 78,111 - 78,111((d))
As at 31 December 2023 439,434 - 439,434
Charge for the year (Note 6) 77,187 - 77,187
Written off (1,542) - (1,542)
As at 31 December 2024 515,079 - 515,079
Carrying amount
As at 31 December 2023 334,578 122,624 457,202
As at 31 December 2024 422,239 - 422,239
((a)) The changes in ARO in Note 35 of US$32.5 million includes the
capitalisation in oil and gas properties of US$18.7million and recognition in
other income of US$13.8 million in Note 13.
In 2023, the changes in ARO in Note 35 of US$19.4 million includes the
increase in ARO of the PNLP Assets of US$24.6 million of which US$12.3 million
is capitalised in this note representing 50% of the working interests owned by
the Group. The remaining 50% of US$12.3 million is offset against the
non-current other payable (Note 39) due to the costs that are to be funded
from the cash advances receivable from the Malaysian joint arrangement
partner.
((b)) For the purpose of the consolidated statement of cash flows, current
year expenditure on oil and gas properties of US$8.7 million remained unpaid
as at 31 December 2024 (2023: US$3.8 million). The additions includes the
capitalisation of borrowing costs of US$5.1 million (2023: US$2.4 million).
((c)) On 31 July 2024, the Group successfully commenced operations of the
Akatara Gas Processing Facility ("Akatara Facility") producing gas, LPG , and
condensate.
((d)) In 2023, the Group assumed operatorship of the PNLP Assets following the
decision of the previous operator to withdraw. Accordingly, the Group has
assumed the previous operator's share of decommissioning liabilities of
US$48.4 million following the transfer of operatorship, with a corresponding
increase to the oil and gas properties balance. The Directors have assessed
the recoverable amount of the oil and gas properties acquired following the
takeover to be zero using the VIU approach. Accordingly, the oil and gas
properties were fully impaired and offset against the non-current other
payable (Note 39) for the reason as explained in (a) above, due to the
uncertainty in respect to a potential restart date for production under the
PSCs and as a result there is no certainty of future cash flows from the oil
and gas properties. On 31 October 2023, MPM 7 invited Jadestone to
participate in the bidding for the renamed PNLP assets, which is now referred
to as the "Puteri Cluster PSC," through Malaysia Bid Round Plus ("MBR+"). The
bid was submitted in January 2024, with result of the bidding was successful
on June 2024. The Group has been awarded the Puteri Cluster PSC as the
operator holding 100% participating interest in the PSC, with 1 July 2024 as
the effective date, being the date the PSC was officially signed between
Malaysia regulator and the Group. With this effect, the PNLP Assets is deemed
relinquished as at 30 June 2024 as disclosed in Note 24.
The remaining impairment amount in the prior year consists of the impairment
of Stag's oil and gas properties for US$17.4 million and PNLP Assets' oil and
gas properties for US$12.3 million as further disclosed in Note 12.
21. PLANT AND EQUIPMENT
Computer equipment Fixtures and fittings Materials and spares
USD'000 USD'000 USD'000 Total
USD'000
Cost
As at 1 January 2023 3,445 1,709 6,036 11,190
Additions 280 236 - 516
Transfer - - 3,122 3,122((a))
As at 31 December 2023 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
Accumulated depreciation
As at 1 January 2023 2,308 1,564 - 3,872
Charge for the year (Note 6) 347 147 - 494
As at 31 December 2023 2,655 1,711 - 4,366
Charge for the year (Note 6) 429 126 - 555
As at 31 December 2024 3,084 1,837 - 4,921
Carrying amount
As at 31 December 2023 1,070 234 9,158 10,462
As at 31 December 2024 1,087 138 9,366 10,591
((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$0.5
million (2023: US$1.7 million).
22. RIGHT-OF-USE ASSETS
Transportation and logistics Buildings
USD'000 USD'000 Total
USD'000
Cost
As at 1 January 2023 46,100 3,643 49,743
Additions 36,926 1,231 38,157
Derecognition (39,673) - (39,673)
As at 31 December 2023 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
Accumulated depreciation
As at 1 January 2023 39,486 2,064 41,550
Charge for the year (Note 6) 14,390 861 15,251
Derecognition (39,673) - (39,673)
As at 31 December 2023 14,203 2,925 17,128
Charge for the year (Note 6) 15,297 898 16,195
Derecognition (5,117) - (5,117)
As at 31 December 2024 24,383 3,823 28,206
Carrying amount
As at 31 December 2023 29,150 1,949 31,099
As at 31 December 2024 14,975 1,136 16,111
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 2.8 years (2023: 2.7
years). The additions to right-of-use assets during the year mainly consist
of the extension on of the transportation and logistic assets.
The maturity analysis of lease liabilities is presented in Note 37.
2024 2023
USD'000 USD'000
Amount recognised in profit or loss
Depreciation expense on right-of-use assets (Note 6) 16,195 15,251
Interest expense on lease liabilities (Note 14) 2,465 2,771
Expenses relating to short-term leases 31,451 36,680
Expense relating to leases of low value assets 292 44
As at 31 December 2024, the Group is committed to US$6.3 million million
(2023: US$3.9 million) of short-term leases.
The total cash outflow in 2024 relating to leases was US$50.7 million (2023:
US$53.9 million).
23. INVESTMENT IN ASSOCIATE
2024 2023
USD'000 USD'000
At beginning of year 26,651 -
Acquisition of 9.52% non-operated interest in Sinphuhorm Assets - 27,853
Dividends received during the year (8,660) (3,842)
Share of profit of the associate 1,553 2,640
At end of year 19,544 26,651
On 19 January 2023, the Group executed a sale and purchase agreement with
Salamander Energy (S.E. Asia) Limited, an affiliate of PT Medco Energi
Internasional Tbk, to acquire its interest in three legal entities, which
collectively own a 9.52% non-operated interest in the producing Sinphuhorm gas
field and a 27.2% interest in the Dong Mun gas discovery onshore north-east
Thailand through APICO LLC. The acquisition included a 27.2% interest in APICO
LLC, which operates the Sinphuhorm concessions (E5N and EU1) and Dong Mun
(L27/43).
The Group accounts for its investment in APICO LLC using the equity method.
The group has 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 has an effective 9.52% non-operated interest in the
Sinphuhorm gas field through its investment in APICO LLC.
APICO LLC is limited liability company incorporated in the State of Delaware,
United States of America. Its primary business purpose is the acquisition,
exploration, development and production of petroleum interests in the Kingdom
of Thailand. Its principal activities are currently exploration in operated
concessions and gas production in non-operated concessions.
The Group has applied equity accounting for the investment in associate. The
summarised financial information in respect of the associate, APICO LLC, since
the date of acquisition of 23 February 2023 is set out below. The summarised
financial information below represents amounts in APICO LLPs' financial
statements which holds a 35% interest in the Sinphuhorm gas field. APICO
LLC's financial statements are prepared in accordance with IFRS Accounting
Standards.
2024 2023
USD'000
USD'000
Current assets 46,414 39,027
Non-current assets 108,686 133,037
Current liabilities 34,665 27,048
Non-current liabilities 6,612 6,902
Revenue 85,775 59,504
Profit before tax 45,639 26,412
Profit after tax, representing total comprehensive income for the year 5,708
9,705
Proportion of the Group's ownership interest in the associate 27.2% 27.2%
Share of profit of the associate 1,553 2,640
Dividends received from the associate during the year (8,660) (3,842)
On 16 April 2025, the Group entered into a sale and purchase agreement with
PTT Exploration and Production Public Company limited ("PTTEP") to sell
Jadestone Energy (Thailand) Pte Ltd, Jadestone Energy (PHT GP) Limited and PHT
Partners LP who collectively hold the effective 9.52% working interest on the
Sinphuhorm gas field via its 27.2% interest in the Dong Mun gas discovery
onshore north-east Thailand through APICO LLC. For further details, please
refer to Note 46.
24. INTERESTS 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 2024 2023
Montara Indefinite Jadestone Energy (Eagle) Pty Ltd Australia 100 100
oilfield
Stag Oilfield 25 August 2039 Jadestone Energy (Australia) Pty Ltd Australia 100 100
PM329 8 December Jadestone Energy (Malaysia) Pte Ltd Malaysia 70 70
2031
PM323 14 June 2028 Jadestone Energy (Malaysia) Pte Ltd Malaysia 60 60
PM318((a)) 30 June 2024 Jadestone Energy (PM) Inc. Malaysia - 100
AAKBNLP((a)) 30 June 2024 Jadestone Energy (PM) Inc. Malaysia - 100
Puteri Cluster
SFA((a)) 30 June 2038 Jadestone Energy (PM) Inc. Malaysia 100 100
PM428 21 April 2053 Jadestone Energy (PM) Inc. Malaysia 100 -
WA-3-L Indefinite Jadestone Energy (CWLH) Pty Ltd Australia 33 17
WA-9-L 15 July 2033 Jadestone Energy (CWLH) Pty Ltd Australia 33 17
WA-11-L 4 September Jadestone Energy (CWLH) Pty Ltd Australia 33 17
2035
WA-16-L 11 September Jadestone Energy (CWLH) Pty Ltd Australia 33 17
2039
46/07 29 June 2035 Mitra Energy (Vietnam Nam Du) Pte Vietnam 100 100
Ltd
51 10 June 2040 Mitra Energy (Vietnam Tho Chu) Pte Vietnam 100 100
Ltd
Lemang 17 January Jadestone Energy (Lemang) Pte Ltd Indonesia 100 100
2037
Sinphuhorm 15 March 2031 Jadestone Energy (Thailand) Pte Ltd Thailand 10 10
concession
(E5N)((b))
Sinphuhorm 2 June 2029 Jadestone Energy (Thailand) Pte Ltd Thailand 10 10
concessions
(EU1)((b))
Dong Mun 24 September Jadestone Energy (Thailand) Pte Ltd Singapore 27 27
(L27/43)((b)) 2017
((a)) The Group has been awarded the Puteri Cluster Small Field Assets ("SFA")
as the operator holding 100% participating interest in the PSC, with 1 July
2024 as the effective date, being the date the PSC was officially signed
between Malaysia regulator and the Group. With this effect, the PM318 and
AAKBNLP Assets is deemed relinquished as at 30 June 2024. The decommissioning
work is set to commence in 2038, hence both the receivable and provision
relating to Putri Cluster has been reclassified from current to non-current as
disclosed in Note 27 and Note 35.
((b)) 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 23 and Note 46.
((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.
25. DEFERRED TAX
The following are the deferred tax liabilities and assets recognised by the
Group and movements thereon.
Australian PRRT Malaysian PITA Tax depreciation Derivative financial instruments
USD'000 USD'000 USD'000 USD'000
Total
USD'000
As at 1 January 2023 1,313 1,605 (70,281) - (67,363)
Credited/(charged) to 4,269 (2,155) 20,138 - 22,252
profit or loss
(Note 16)
Credited to OCI - - - 6,056 6,056
As at 31 December 5,582 (550) (50,143) 6,056 (39,055)
2023 and 1 January
2024
Credited/(charged) to 10,031 (5,473) 1,909 - 6,467
profit or loss
(Note 16)
Credited to OCI - - - (3,770) (3,770)
Acquisition of - - 19,731 - 19,731
additional interest
of CWLH Assets
(Note 18)
Reclassification of - - 1,905 - 1,905
carried forward
business losses
As at 31 December 15,613 (6,023) (26,598) 2,286 (14,722)
2024
The following is the analysis of the deferred tax balances (after offset) 8
for financial reporting purposes:
31 December 2024 31 December 2023
USD'000 USD'000
Deferred tax liabilities (59,620) (65,829)
Deferred tax assets 44,898 26,774
(14,722) (39,055)
The Group's deferred tax assets predominately arising from its Australian
operations and PenMal Assets. Deferred tax assets are recognised 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 recognised 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 utilise the losses.
The Group has unutilised PRRT credits of approximately US$4.1 billion (2023:
US$3.8 billion) and US$802.4 million (2023: US$493.4 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 recognised 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 utilised
based on a last-in-first-out basis, the unutilised PRRT credits of
approximately US$4.1 billion (2023: US$3.8 billion) and US$802.4million (2023:
US$493.4 million) with respect to Montara and the CWLH Assets are not expected
to be utilised and are therefore not recognised as a deferred tax asset.
26. INVENTORIES
2024 2023
USD'000 USD'000
Materials and spares 30,164 23,242
Less: allowance for slow moving (9,960) (7,010)
20,204 16,232
Crude oil inventories 24,398 17,422
44,602 33,654
The cost of inventories of US$323.0 million (2023: US$270.4 million)
recognised 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.
27. TRADE AND OTHER RECEIVABLES
2024 2023
USD'000 USD'000
Current assets
Trade receivables 15,846 12,533
Prepayments 8,459 5,947
Other receivables 7,731 88,005
Amount due from joint arrangement partners (net) 2,390 12,911
Underlift crude oil inventories 12,278 3,539
GST/VAT receivables 8,797 1,444
55,501 124,379
Allowance for expected credit loss (Note 10) (457) -
55,044 124,379
Non-current assets
Other receivables 261,517 127,730
GST/VAT receivables 12,607 14,130
274,124 141,860
329,168 266,239
Set out below is the movement in the allowance for expected credit losses of
trade receivables:
2024
USD'000
As at 1 January 2024
Allowance for expected credit losses (Note 10) 457
As at 31 December 2024 457
Trade receivables arise from revenues generated from operations in Australia,
Malaysia and Indonesia. The average credit period is 30 days (2023: 30 days).
The Group has recognised an allowance for expected credit losses of US$0.5
million and remaining outstanding receivables as at 31 December 2024 and 2023
have been recovered in full in 2025 and 2024, 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 received in
January 2025.
The underlift crude oil inventories represent entitlement imbalances at year
end of 9,950 bbls and 386,451 bbls at the PenMal operated assets and CWLH
Asset measured at cost of US$17.34/bbl and US$31.32/bbl respectively. The 2024
underlift position will unwind in 2025 based on the subsequent net productions
entitled to the Group. The Group was in underlift position at 2023 year end
which unwound in 2024 based on actual production entitlement during the year.
The current other receivables in 2023 represent the accumulated amount due
from a joint arrangement partner of Penmal PNLP Assets for its share of future
wells preservation activities and decommissioning costs when it exited two PSC
licenses during 2023. Subsequently in 2024, the Puteri Cluster cess fund of
US$47.8 million has been reclassified to non-current as further disclosed in
Note 24.
Non-current other receivables represent the accumulated cess payment paid to
the Malaysian and Indonesian regulators for the operated licenses and an
abandonment trust fund set up following the acquisition of the CWLH Assets.
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, while the abandonment trust fund was
set up as part of the acquisition of the CWLH Assets. The payments made were
to ensure there are sufficient funds available for decommissioning
expenditures activities at the end of the fields' life. The cess payment
amount is assessed based on the estimated future decommissioning expenditures.
In 2023, the increase of non-current other receivables during the period
represents additional payments of US$41.0 million into the CWLH abandonment
trust fund. Additionally, the total accumulated cess payment paid to the
Malaysian regulator and the ARO provision for the PNLP Assets are now
presented on a gross basis following the reallocation of the CESS funds when
the licenses and operatorship were transferred to the Group in April 2023, in
line with the Group's accounting policies.
In 2024, the increase of non-current other receivables due to the abandonment
trust fund payments which was required under acquisition of additional
interest in CWLH Assets as disclosed in Note 18 and the reclassification of
Puteri Cluster cess fund of US$47.8 million from current to non-current as
disclosed in Note 24.
There are no trade receivables older than 30 days apart from those that have
recognised an allowance for expected credit losses. The credit risk associated
with the trade receivables is disclosed in Note 42.
28. CASH AND BANK BALANCES
2024 2023
USD'000 USD'000
Cash and bank balances, representing cash and cash equivalents in the
consolidated statement of cash flows, presented as:
Non-current 888 1,008
Current 94,338 152,396
95,226 153,404
The non-current cash and cash equivalents represents the restricted cash
balance of US$0.6 million (2023: US$0.7 million) and US$0.3 million (2023:
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 place 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 2024.
Current cash and cash equivalents include a bank guarantee of US$0.3 million
(2023: US$0.5 million) and US$3.0 million (2023: US$Nil) placed by the Group
during the year with respect to the construction of the Lemang PSC gas
pipeline facilities and PenMal Asset. These deposits place 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 2024.
As part of the RBL facility as disclosed in Note 36, 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
2024, the DSRA contained US$8.2 million (2023: US$ 8.2 million) in advance of
the interest payable in March 2025.
29. SHARE CAPITAL AND SHARE PREMIUM ACCOUNT
Share capital Share premium account
No. of shares USD'000 USD'000
Issued and fully paid
As at 1 January 2023, at £0.001 each 448,353,663 339 983
Issued during the year 94,463,933 120 50,844
Shares repurchased (2,051,022) (3) -
As at 31 December 2023 540,766,574 456 51,827
Issued during the year (Note 32) 344,225 1 349
As at 31 December 2024 541,110,799 457 52,176
During the year, no employee share options were exercised and issued (2023:
128,160 shares; GB£0.56 per share). Additionally, no shares (2023: 79,327
shares) were issued during the year to satisfy the Company's obligations with
regards to the performance shares and 344,225 shares (2023: 101,063 shares)
were issued to meet the obligations with regards to the restricted
shares 9 .
The share buyback programme was launched in 2022 with a maximum amount of
US$25.0 million and will not exceed 46,574,528 shares. On 19 January 2023, the
Company suspended its share buyback programme. For the year ended 31 December
2023, the Company had acquired 2.3 million shares at a weighted average cost
of GB£0.75 per share, resulting in total expenditure of US$2.1 million. The
total nominal value of the shares repurchased was US$2,485. All shares
repurchased were cancelled.
On 6 June 2023, the Company completed an equity fundraising, creating an
additional 94,081,826 ordinary shares at GB£0.45 per share, which comprised
of a placing and subscription of 92,312,691 new ordinary shares to existing
and new institutional shareholders and a placing and subscription of 1,769,135
new ordinary shares to the Directors of the Company. Total gross proceeds were
US$53.0 million, with net proceeds of US$51.0 million. The Group incurred
total costs of US$2.0 million associated with the equity fundraising and these
costs were accounted as a deduction to the equity.
On 9 June 2023, the Company launched an open offer of up to 14,887,039 new
ordinary shares, at GB£0.45 per share, to raise additional proceeds of up to
EUR8.0 million 10 (up to US$8.6 million). The open offer closed on 28 June
2023, raising a total gross and net proceeds of US$42,009 by issuing 73,557
new shares.
The Company has one class of ordinary share. Fully paid ordinary shares with
par value of GB£0.001 per share carry one vote per share without restriction,
and carry a right to dividends as and when declared by the Company.
30. DIVIDENDS
The Company did not declare any dividend during the year (2023: US$Nil).
31. 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 reorganisation in 2021.
32. SHARE-BASED PAYMENTS RESERVE
Share-based payments reserve represents the cumulative value of share-based
payment expenses recognised 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$0.4 million (2023:
US$0.8 million) was recognised as 'administrative staff costs' (Note 7) in
profit or loss for the year ended 31 December 2024.
During the year, 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 29.
The share-based payment expense arose from share options, performance shares
and restricted shares 11 were awarded from 2020 to 2022. The performance
share grants were suspended in 2023 by the Remuneration Committee in view of
the performance of the Group in 2023. In consultation with an external
advisor, the Remuneration Committee approved a Deferred Cash Plan ("DCP") for
the 2023 - 2026 Long-Term Incentive ("LTI") cycle, which was awarded in
October 2023 (Note 39). 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.
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.
32.1 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
9 March 2022
Risk-free rate 1.34% to 1.38%
Expected life 5.5 to 6.5 years
Expected volatility 12 63.0% to 66.7%
Share price GB£ 1.01
Exercise price GB£ 0.92
Expected dividends 1.96%
32.2 Performance shares
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).
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
9 March 2022
Risk-free rate 1.39%
Expected volatility 13 53.1%
Share price GB£ 1.01
Exercise price N/A
Expected dividends 1.71%
Post-vesting withdrawal date N/A
Early exercise assumption N/A
32.3 Restricted shares 14
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
22 August 2022 9 March 2022
Risk-free rate 1.73% 1.39%
Share price GB£ 0.90 GB£ 1.01
Expected dividends 1.73% 1.71%
The following table summarises the options/shares under the LTI plans
outstanding and exercisable as at 31 December 2024:
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 2023 2,745,943 445,288 19,738,936 0.45 7.15 12,316,331
Vested during the (79,327) (101,063) - 0.44 6.32 4,665,000
year
Exercised during the - - (128,160) 0.56 - (128,160)
year
Expired unexercised (449,513) - - - - -
during the year
Cancelled during the - - (344,655) 0.60 - (344,655)
year
As at 31 December 2,217,103 344,225 19,266,121 0.48 5.37 16,508,516
2023
Vested during the - (344,225) 0.76 7.19 2,118,585
year
Expired unexercised (967,794) - (125,418) 0.59 - (125,418)
during the year
Granted during the - 1,242,000 - - - -
year
As at 31 December 1,249,309 1,242,000 19,140,703 0.45 4.67 18,501,683
2024
The weighted average share price on the exercise date in 2023 was GB£0.83.
Range of Weighted average Weighted
exercise exercise average
Number of options price price GB£ remaining
GB£ contract life
Share options exercisable as at 31 December 2023 16,508,516 0.26 - 0.99 0.41 4.92
Share options exercisable as at 31 December 2024 18,501,683 0.26 - 0.99 0.45 4.67
33. 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 29).
34. HEDGING RESERVE
2024 2023
USD'000 USD'000
At beginning of the year 14,131 -
Loss arising on changes in fair value of hedging instruments during 14,849 30,509
the year
Income tax related to loss recognized in other comprehensive income (4,455) (9,153)
Net loss reclassified to profit or loss (Note 4) (27,417) (10,322)
Income tax related to amounts reclassified to profit or loss 8,225 3,097
At end of the year 5,333 14,131
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 recognised in profit or
loss only when the hedged transaction impacts the profit or loss. See Note
40 for further details on the hedging arrangements.
35. PROVISIONS
Asset restoration obligations((a))
USD'000 Contingent payments((b)) Employees benefits((c))
USD'000 USD'000 Others Total
USD'000 USD'000
As at 1 January 2023 496,391 14,372 885 - 511,648
Charged/(Credited) to profit or loss - (7,653) 149 1,112 (6,392)
Accretion expense (Note 14) 20,201 - - - 20,201
Change in estimation (Note 20) 19,420 - - - 19,420
Payment/Utilised (8,589) - - - (8,589)
Fair value adjustment - Lemang PSC
(Note 14) - 868 - - 868
Fair value adjustment - CWLH Assets - 60 - - 60
(Note 14)
Acquisition of 50% interest in PNLP
Assets 48,430 - - - 48,430
Gross Up (Note 27) 28,176 - - - 28,176
Reclassification (127) (2,000) - - (2,127)
As at 31 December 2023 and 1 January 2024
603,902 5,647 1,034 1,112 611,695
Credited to profit or loss - - - (1,112) ((f)) (1,112)((f))
Accretion expense (Note 14) 22,544 - - - 22,544
Change in estimation (Notes 13 and
and 20) (32,518) - - - (32,518)
Payment/Utilised - (5,000) (12) - (5,012)
Fair value adjustment - Lemang PSC
(Note 14) - 53 - - 53
Acquisition of additional interest of
CWLH Assets (Note 18) 65,881 - - - 65,881
Additions during the year (Note 19)((g)) - - - 10,000((g)) 10,000((g))
Reclassification (1,038)((d)) - - - (1,038)((d))
As at 31 December 2024 658,771 700 1,022 10,000 670,493
As at 31 December 2023
Current 102,811((e)) 5,000 714 - 108,525
Non-current 501,091 647 320 1,112 503,170
603,902 5,647 1,034 1,112 611,695
As at 31 December 2024
Current 4,109((e)) 700 733 - 5,542
Non-current 654,662 - 289 10,000 664,951
658,771 700 1,022 10,000 670,493
( )
((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 2023. There is an addition of
US$62.6 million mainly due to the acquisition of additional interest of CWLH
Assets as disclosed in Note 18. 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
2024 2023 2024 2023
1. Montara 2.40% 2.55% 4.32% 3.99% 2031
2. Stag 2.30% 2.30% 4.60% 4.08% 2036
3. Lemang PSC 2.45% 2.24% 6.45% 6.09% 2036
4. PenMal Assets 2.15% 2.09% 3.67% - 3.89% 3.52% - 3.80% 2026 onwards
5. CWLH Assets 2.41% 2.58% 4.51% 4.03% 2036
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 favour 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 recognised 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 non-current receivable 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 2024 (2023: US$5.6 million) for the trigger
events as disclosed below. The decrease in provision represents the
derecognition of contingent payments associated with the Saudi CP and Dated
Brent prices due to the trigger events are not expected to occur based on the
specialist's consensus on Dated Brent prices and the historical correlation
between Dated Brent prices and Saudi CP and payment made after the first gas
date of 31 July 2024.
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.
aggregate amount of US$6.7 million on a gross basis
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 2023 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 The average Saudi CP is not above US$620/MT in 2024, which is the year of
operation.
6. The average Saudi CP in the second year of operation is higher than US$620/MT US$2.0 million The average Saudi CP is not expected to be above US$620/MT in 2025, the second
year of production. The contingent payment will be due for payment within 15
business days of the occurrence of the trigger event if it falls due.
7. The average Dated Brent price in the first year of operation is higher than US$2.5 million The average Dated Brent price is not expected to be above US$80/bbl in 2024,
US$80/bbl which is the year of operation.
No. Trigger event Consideration Directors' rationale
8. The average Dated Brent price in the second year of operation is higher than US$1.5 million The average Dated Brent price is not expected to be above US$80/bbl in 2025,
US$80/bbl the second year of production. The contingent payment will be due for
payment within 15 business days of the occurrence of the trigger event if it
falls due.
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) ) US$1.0 million reclassification related to the abandonment
payment made from the CWLH Asset trust fund, following the operator's
statement which was recorded under asset retirement obligations.
((e) ) US$102.8 million was reclassified from current asset
restoration obligations to non-current asset restoration obligation due to the
deferral of decommissioning activities for the Penmal Puteri Cluster SFA as
disclosed in Note 24.
((f) ) US$1.1 million credited to profit or loss due to a change
in underlying assumptions for provisions for manpower related at Montara.
((g) ) During the year, 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 expects to receive approval
from Vietnamese regulatory authorities in the second half of 2025. The
commitment well obligation had previously received several extensions
approvals from PetroVietnam, with the final extension expiring on 29 June
2024. According to the production sharing contract terms, should the FDP not
receive approval from the relevant authorities, the group would be liable for
a US$10.0 million penalty payable to PetroVietnam within 30 days of formal
rejection notification. The Nam Du field is estimated to contain approximately
93.9 mmboe of 2C contingent resource.
36. BORROWINGS
2024 2023
USD'000 Reclassified*
USD'000
Non-current secured borrowings
Reserve based lending facility 122,978 131,729
Current secured borrowings
Reserve based lending facility 77,212 22,844
200,190 154,573
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 15 (#_ftn15) (which
is expected later).
The borrowing base 16 (#_ftn16) 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 18. 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
favour 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.
The maximum facility limit is at US$200.0 million. The borrowing base was at
US$200 million throughout the financial year 2024 (2023: US$200 million), and
at the March 2025 redetermination, it was reduced to US$167.0 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 2024, the Group had incurred total interest expenses of
US$21.5 million (2023: US$10.2 million) and US$0.1 million of commitment fees
(2023: US$0.6 million), of which US$5.1 million (US$2.4 million) has been
capitalised as disclosed in Note 20. The net interest expenses of US$16.4
million (2023: US$8.1 million) and US$0.1 million (2023: US$0.3 million)
commitment fees are disclosed in Note 14.
* US$15.8 million of borrowings reported as at 31 December 2023 has been
reclassified from non-current to current following changes in the basis of
assumptions.
The Group entered into a committed standby working capital facility with Tyrus
Capital S.à.r.l as part of the equity raise on 6
June 2023 for US$31.9 million. This facility matured on 31 December 2024. The
facility carried interest of 15% on drawn amounts and 5% on undrawn amounts.
For the year ended 31 December 2024, the Group incurred interest expense of
US$1.5 million (2023: US$1.0 million) as disclosed in Note 14.
The secured borrowings 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 42. The group has complied with
this covenant in 2024 and 2023
37. LEASE LIABILITIES
2024 2023
USD'000 USD'000
Presented as:
Non-current 5,308 18,746
Current 12,243 14,118
17,551 32,864
Maturity analysis of lease liabilities based on undiscounted gross cash
flows:
Year 1 15,083 17,357
Year 2 3,571 14,662
Year 3 - 3,674
Future interest charge (1,103) (2,829)
17,551 32,864
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.
38. 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 USD'000
USD'000
As at 1 January 2023 - 9,107
Repayment of lease liabilities - (17,171)
Repayment of borrowings (75,000) -
Total drawdown of borrowings 232,000 -
New lease liabilities - 38,157
Borrowings costs paid (7,595) -
IInterest on borrowings paid (5,007) -
Commitment fees of borrowings paid (658) -
Interest expense 2,571 -
RBL commitment fees 349 -
Non-cash changes - interest 5,518 2,771
Capitalisation of borrowing costs (Note 20) 2,395 -
As at 31 December 2023 and 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
Capitalisation of borrowing costs (Note 20) 5,133 -
As at 31 December 2024 200,190 17,551
39. TRADE AND OTHER PAYABLES
2024 2023
USD'000 USD'000
Current
Trade payables 26,520 36,056
Other payables 12,809 13,105*
Accruals 51,805 56,534
Contingent payments - 2,000
Malaysian supplementary payment payables 392 2,152
Amount due to joint arrangement partner 1,082 1,252
Overlift crude oil inventories - 6,004
GST/VAT payables 185 881
92,793 117,984
Non-current
Other payable 16,917 16,917
Accrual 365 49
17,282 16,966
110,075 134,950
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 (2023: 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 contingent payment in 2023 relates to the final contingent payment payable
to BP which arose from the initial acquisition of the CWLH Assets as the
annual average Brent crude price in 2023 exceeded US$60/bbl. The payment was
made in January 2024.
The overlift crude oil inventories in 2023 represent entitlement imbalances at
year end of 195,698 bbls at the CWLH. The overlift liabilities are measured at
cost of US$30.68/bbl. The CWLH Assets are in an underlift position as at 2024
year end as disclosed in Note 27.
The non-current other payable represents future activities which are
operational in nature for which cash advances are to be received from the
Malaysian joint arrangement partner for its share of future wells preservation
activities and decommissioning costs on the PNLP Assets when it withdrew from
the licenses in 2023 as disclosed in Note 27.
*US$4.5 million relating to outstanding swap contracts that matured in Quarter
4 in 2023 and were settled in January 2024 has been reclassified from
derivative financial instruments to other payables as at 31 December 2023.
The non-current accrual represents the DCP plan granted during the year as
disclosed in Note 32. The DCP has a vesting period of three years with
pre-conditions for vesting to take place. The three years vesting period will
also be the assessment period to assess if the pre-conditions are met. Upon
vesting period of three years with pre-condition met, DCP will be settled by
cash on different payout rates subject to the performance of the Group. The
performance measures for DCP is similar to the performance shares as disclosed
in Note 32.2. The DCP is measured at fair value as at 31 December 2024.
40. DERIVATIVE FINANCIAL INSTRUMENTS
2024 2023
USD'000 USD'000
*Reclassified
Derivative financial liabilities
Designated as cash flow hedges
Commodity swap 7,618 20,607
Measured at fair value though profit or loss
Foreign exchange forward contracts - 73
7,618 20,680
Analysed as:
Current 7,618 13,972
Non-current - 6,708
7,618 20,680
.
The following is a summary of the Group's outstanding derivative contracts:
Fair value asset at Fair value asset at
31 December 2024 31 December
USD'000 2023
Contract quantity Type of contracts Hedge classification USD'000
Term Contract price
Contracts designated as cash flow hedges
50% of Commodity Oct Weighted Cash flow (7,618) (20,607)*
Group's swap: 2023 - average price of
planned swap Sep US$70.57/bbl
2P component((a)) 2025
production
*US$4.5 million relating to outstanding swap contracts that matured in Quarter
4 in 2023 and were settled in January 2024 has been reclassified from
derivative financial instruments to other payables as at 31 December 2023
Fair value asset at Fair value asset at
31 December 2024 31 December
USD'000 2023
Contract quantity Type of contracts Hedge classification USD'000
Term Contract price
Contracts that are not designated in hedge accounting relationships
To hedge Foreign Execution USD/MYR: 4.60 FVTPL - (73)
MYR162.5 exchange date: 2
million by forward February
selling MYR contracts 2024
for USD
((a)) Swap component referring to hedge sales and the price of the commodity.
The Group's October 2023 to September 2025 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.
In August 2023, the Group entered into a foreign exchange forward contract
with a bank based in Malaysia to hedge MYR162.5 million (approximately US$35.4
million), being the receivable sum at 2023 year end due from the joint
arrangement partner of PNLP Assets for its share of future decommissioning
costs when it exited two PSC licenses. The forward contract was to secure
the receipts in USD in view of volatility of MYR against USD towards the end
of 2023. The forward contract matured on 2 February 2024 following the
receipts of the sum from the joint arrangement partner in January 2024. No
such contract entered in 2024.
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
USD'000
Oil volumes Notional value Fair value
bbls USD'000 USD'000
2023
Cash flow hedges
Commodity swap component 4,531,720 317,629 - 20,680
2024
Cash flow hedges
Commodity swap component 1,733,020 119,698 - 7,618
( )
The following table details the effectiveness of the hedging relationships and
the amounts reclassified from
hedging reserve to profit or loss:
Current period hedging loss recognised in OCI Amount of hedge ineffectiveness recognised 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
USD'000 USD'000
USD'000
2023
Cash flow hedges
Forecast sales (20,680)* - Other expenses (10,322) Revenue
2024
Cash flow hedges
Forecast sales (7,618) - Other expenses (27,417) Revenue
*US$4.5 million relating to outstanding swap contracts that matured in Quarter
4 in 2023 and were settled in January 2024 has been reclassified from
derivative financial instruments to other payables as at 31 December 2023.
41. 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 2024, the fair value of warrant liability
was US$0.9 million (2023: US$3.5 million). The movement in the fair value of
warrants liability of US$2.5 million is disclosed in Note 15.
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:
2024 2023
Risk-free rate 4.48% 3.77%
Expected life 1.4 years 2.5 years
Expected volatility 17 (#_ftn17) 59.5% 54.5%
Share price GB£ 0.24 GB£ 0.37
Exercise price GB£ 0.50 GB£ 0.50
Expected dividends 0% 0%
42. FINANCIAL INSTRUMENTS, 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 due to the carrying amount representing the actual cash paid.
2024 2023
USD'000 USD'000
Financial assets
At amortised cost
Trade and other receivables, excluding prepayments, GST/VAT 287,027 241,179
receivables and underlift crude oil inventories
Cash and bank balances 95,226 153,404
382,253 394,583
Financial liabilities
At amortised cost
Trade and other payables, excluding contingent payments, GST/VAT payables 109,890 126,065*
and overlift
crude oil inventories
Lease liabilities 17,551 32,864
Borrowings 200,190 154,573
Contingent consideration for Lemang PSC acquisition 700 5,647
Contingent consideration for CWLH Assets acquisition - 2,000
328,331 321,149
*US$4.5 million relating to outstanding swap contracts that matured in Quarter
4 in 2023 and were settled in January 2024 has been reclassified from
derivative financial instruments to other payables as at 31 December 2023.
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 realises 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 50% of its
forecasted production from October 2023 to September 2025 (Note 40).
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 summarises 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.
Reasonably possible movements in commodity prices were determined based on a
review of recent historical prices and current economic forecasters'
estimates.
Effect on the Effect on other Effect on the Effect on other
result comprehensive result comprehensive
before tax for the income before tax before tax for the income before tax
year ended for the year ended year ended for the year ended
31 December 2024 31 December 2024 31 December 2023 31 December 2023
Gain or loss USD'000 USD'000 USD'000 USD'000
Increase by 10% - (12,732) - (33,861)
Decrease by 10% - 12,732 - 33,861
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 minimise 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 USD 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:
2024 2023
USD'000 USD'000
Cash and bank balances
Australian Dollars 1,894 4,777
Malaysian Ringgit 4,820 8,533
Trade and other receivables
Australian Dollars 21,826 250
Malaysian Ringgit 9,837 42,672
Trade and other payables
Australian Dollars 41,676 33,250
Malaysian Ringgit 42,027 59,113
A strengthening/weakening of the Australian dollar and Malaysian Ringgit 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$4.1 million (2023:
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 2024, the Group held US$165.8 million (2023: US$82.0
million) in the CWLH Assets abandonment trust fund operated by the joint
venture operating partner. The abandonment trust funds generates average
annual interest rate of 3.16% (2023: 4.5%).
As at 31 December 2024, the Group held US$Nil million (2023: US$55.0 million)
in fixed term deposits. The fixed term deposits generate average annual
interest rate of 4.5% (2023: 4.5%).
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 RBL Banks"). The facility tenor is four years, with the final maturity
date being the earlier of 31 March 2027 and the projected reserves tail 18
(which is expected later). The borrowing base 19 is secured over the
Group's main producing assets being Montara, Stag, CWLH, Sinphuhorm Assets,
the PenMal PM323 and PM329 PSCs and the Group's development asset being the
Lemang PSC. The maximum facility limit is at US$200.0 million. The borrowing
base was at US$200 million throughout the financial year 2024 (2023: US$200
million), and at the March 2025 redetermination, it was reduced to US$167.0
million.
As at 31 December 2024 the Group has a net drawdown sum of US$200.0 million
(2023: US$157.0 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 2024, 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
(2023: profit before tax 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 recognised, creditworthy third parties.
The Group's current credit risk grading framework comprises the following
categories:
Category Description Basis for recognising expected credit losses ("ECL")
Performing The counterparty has a low risk of default and does not have any past due 12-month ECL 20
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
allowance
Note rating rating lifetime ECL USD'000 USD'000 USD'000
2024
Cash and bank 95,226 -* 95,226
balances 28 n.a Performing 12m ECL
Trade 27 A2 (i) Lifetime ECL 15,846 -* 15,846
receivables
Other 27 n.a (i) 12m ECL 7,731 -* 7,731
receivables
Amount due 27 n.a (i) 12m ECL 2,390 -* 2,390
from joint
arrangement
partners (net)
Non-current 27 n.a (i) 12m ECL 261,517 -* 261,517
other
receivables
2023
Cash and bank 153,404 -* 153,404
balances 28 n.a Performing 12m ECL
Trade 27 A2 (i) Lifetime ECL 12,533 -* 12,533
receivables
Other 27 n.a (i) 12m ECL 88,005 -* 88,005
receivables
Amount due 27 n.a (i) 12m ECL 12,911 -* 12,911
from joint
arrangement
partners (net)
Non-current 27 n.a (i) 12m ECL 127,730 -* 127,730
other
receivables
* 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 2024, total trade receivables amounted to US$15.8 million
(2023: US$12.5 million). The balance in 2024 and 2023 had been fully recovered
in 2025 and 2024, respectively, except for US$0.5 million (2023: US$Nil)
allowance for expected credit loss has been recognised 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$44.1 million (2023: US$91.3
million). Operating cash flows before movements in working capital and net
cash used in operating activities for the year ended 31 December 2024 was
US$70.5 million and US$30.7 million (2023: US$36.5 million and US$12.1
million) respectively. The Group's net current asset remained positive at
US$9.2 million as at 31 December 2024 (2023: US$22.3 million).
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 RBL Banks"). The facility tenor is four years, with the final maturity
date being the earlier of 31 March 2027 and the projected reserves tail
(which is expected later). The borrowing base is secured over the
Group's main producing assets being Montara, Stag, CWLH, Sinphuhorm Assets,
the PenMal PM323 and PM329 PSCs and the Group's development asset being the
Lemang PSC. The maximum facility limit is at US$200.0 million. The maximum
facility limit is at US$200.0 million. The borrowing base was at US$200
million throughout the financial year 2024 (2023: US$200 million), and at the
March 2025 redetermination, it was reduced to US$167.0 million.
The Group is required to maintain a parent company financial covenant as
disclosed in Note 36 of consolidated net debt below 3.5x annual EBITDAX and to
deliver the required information to the RBL Banks on a timely basis. As at 31
December 2024, the Company's financial covenant was 1.20 (2023: 0.14).
Further details are disclosed in the Going Concern section in Note 2.
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
% USD'000 USD'000 USD'000 USD'000
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
Derivative 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
2023
Non-interest bearing
Trade and other payables, excluding contingent payments, GST/VAT - 109,099 16,966 - 126,065
payables
and overlift crude oil inventories*
Contingent consideration for Lemang PSC acquisition - 5,000 647 - 5,647
Contingent consideration for CWLH Assets acquisition - 2,000 - - 2,000
Derivative financial instruments designated as cash flow hedges* - 13,972 6,708 - 20,680
Derivative financial instrument carried at FVTPL - 73 - - 73
Fixed interest rate instrument
Lease liabilities 9.660 14,118 18,746 - 32,864
Variable interest rate instrument
Borrowings* 11.084 22,844 131,729 - 154,573
167,106 174,796 - 341,902
* US$15.8 million of borrowings reported as at 31 December 2023 has been
reclassified from non-current to current as disclosed in Note 36. US$4.5
million of derivative financial liabilities instruments as at 31 December 2023
has been reclassified to trade and other payables as disclosed in Note 39 and
Note 40.
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 5 years Total
% USD'000 USD'000 USD'000 USD'000
2024
Non-interest bearing
Trade and other receivables, - 25,510 261,517 - 287,027
excluding prepayments, GST/VAT
receivables and underlift crude
oil inventories((a))
Variable interest rate instruments
Cash and bank balances -((b)) 94,338 888 - 95,226
119,848 262,405 - 382,253
2023
Non-interest bearing
Trade and other receivables, - 113,449 127,730 - 241,179
excluding prepayments, GST/VAT
receivables and underlift crude
oil inventories
Variable interest rate instruments
Cash and bank balances -((b)) 152,396 1,008 - 153,404
265,845 128,738 - 394,583
( )
((a)) There are US$6.3 million (2023: US$2.9 million) of abandonment trust
funds that are interest bearing with a weighted average effective interest
rate of 3.16% (2023: 4.5%)
((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 29, 31, 32, 33
and 34, respectively.
To carry-out planned asset acquisitions, exploration and development, and to
pay for administrative costs, the Group may utilise excess cash generated from
its ongoing operations and may utilise 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 reflects
increased borrowings to fund the Akatara gas facility and the second tranche
acquisition of CWLH, as well as a reduction in equity due to higher upfront
borrowing costs reserve.These impacts were incurred without the benefit of a
full year of incremental production contributions from these investments.
Looking ahead, these investments, together with the sale of Sinphuhorm, are
expected to strengthen equity and reduce borrowings over time.
2024 2023
USD'000 USD'000
Gearing ratio
Borrowings 200,190 21 (#_ftn21) 154,5731
Cash and cash equivalents (95,226) (153,404)
Net debt/(cash) 104,964 1,169
Equity 18,834 53,770
Net debt to equity ratio 5.57 0.02
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 (USD'000) as at Valuation Relationship of
Financial assets/financial 2024 2023 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 - 7,168 - 20,607* Level 2 Third party valuations based on market comparable information. - -
contracts (Note 40)
2) Foreign forward - - - 73 Level 2 Third party valuations based on market comparable information. - -
contracts (Note 40)
Others - contingent consideration from Lemang PSC acquisition
3) Contingent consideration (Note 35) - 700 - 5,647 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$73.00/bbl in 2025 and
Saudi CP prices of
US$587.95/MT in 2025,
estimated future recoverability
of VAT receivables as well as
the effect of the time value of
money.
*US$4.5 million relating to outstanding swap contracts that matured in Quarter
4 in 2023 and were settled in January 2024 has been reclassified from
derivative financial instruments to other payables as at 31 December 2023.
Fair value (USD'000) as at Valuation Relationship of
Financial assets/financial 2024 2023 Fair value technique(s) Significant unobservable inputs
liabilities Assets Liabilities Assets Liabilities hierarchy and key input(s) unobservable input(s) to fair value
Others - contingent consideration from CWLH Assets acquisition
4) Contingent consideration - - - 2,000 Level 1 Based on the actual average - -
(Notes 35 and 39) Dated Brent prices in 2023
of US$82.64/bbl.
1. 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 Thailand.
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 Vietnam Indonesia Corporate Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'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 (221,844) (43,277) (11,848) - - - - (276,969)
Depletion, depreciation and amortisation (77,297)
(10,956) (2,809) - (89) - (256) (91,407)
Administrative staff (15,082) (5,427) (393) (1,162) (535) (11,824) (34,423)
costs -
Other expenses (8,949) (4,693) (3,220) (1,623) (463) (624) (4,744) (24,316)
Share of results of - - - 1,553 - - - 1,553
associate
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.
Producing assets Exploration/development
Australia Malaysia((b)) Indonesia((b)) Thailand((b)) Vietnam((b)) Indonesia((b)) Corporate Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
2023
Revenue
Liquids revenue 240,630 66,517 - - - - - 307,147
Gas revenue - 2,053 - - - - - 2,053
240,630 68,570 - - - - - 309,200
Production cost (185,039) (47,733) - - - - - (232,772)
Depletion, depreciation and amortisation (65,204) -
(10,397) - (90) (158) (292) (76,141)
Administrative staff (14,550) (5,060) - (1,773) - (8,814) (30,197)
costs -
Other expenses (12,652) (3,182) - (181) (395) (1,924) (4,507) (22,841)
Impairment of assets (17,410) (12,271) - - - - - (29,681)
Share of results of - - - - - - 2,640
associate 2,640
Other income 9,990 192 - - 25 7,659 989 18,855
Finance costs (22,611) (6,565) - - - (2,274) (10,379) (41,829)
(Loss)/Profit before tax (66,846) (16,446) - 2,459 (2,233) 3,303 (23,003) (102,766)
Additions to non- 86,403 54,576 - - 90,611 - 703 232,293
current assets
Non-current assets((a)) 346,281 164,899 - 26,651 72,556 136,817 642 747,846
((a)) The non-current assets in the segmental note exclude deferred tax assets
from the consolidated statement of financial position.
((b)) The SEA category from the prior year has been split into Malaysia,
Indonesia, and Thailand, while the Exploration/Development category has been
separated into Vietnam and Indonesia. Accordingly, the prior year figures have
been reclassified to reflect these change.
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.
43. FINANCIAL CAPITAL COMMITMENTS
Certain PSCs and service concessions have firm capital commitments. The
Group has the following outstanding minimum commitments:
SEA portfolio PSC operational commitments
2024 2023
USD'000 USD'000
Not later than one year 460 10,400
One to five years 9,404 9,284
More than 5 years 1,978 2,619
11,842 22,303
The SEA portfolio PSC operational commitment as at 31 December 2024 amounted
to US$7.3 million (2023: US$ 17.3 million) relates to Lemang PSC. In 2023,
US$10.0 million relates to the minimum work commitment outstanding for the
Block 46/07 PSC which provision has been provided this year as disclosed in
Note 35. The operational commitments also include training commitment of
US$4.7 million (2023: US$5.0 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$7.3 million
(2023: US$7.3 million) consisting of one exploration well and a 3D seismic
programme. The work commitments should have been completed during the
exploration phase of the PSC by the previous owner. It has been agreed with
the Indonesian regulator that the work commitments can be completed after
first gas in 2024 but before the end of 2026.
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$0.4 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 (2023: US$0.3 million),
US$0.1 million (2023:US$Nil) and US$Nil (2023: US$0.1 million) for PM323 PSC,
PM428 PSC and PM318 PSC, 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 recognised as
liabilities:
2024 2023
USD'000 USD'000
Not later than one year 13,611 28,489
One to five years 2,652 2,570
16,263 31,059
The capital commitments of US$11.8 million as at 2024 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 project has been completed during the year and the group
successfully commenced operations on 31 July 2024.
The Group also contracted for US$4.2 million for capital expenditure
replacement in Montara and US$0.2 million which is associated with Stag
capital expenditure.
44. CONTINGENT LIABILITIES
Montara Venture FPSO investigation
On 17 June 2022, a loss of containment of between three and five cubic metres
of oil occurred at the Montara Venture FPSO. The facility was shut-in
immediately and the incident was reported to the local regulator. The local
regulator has commenced an investigation into the incident for potential
breach of the local regulations. The investigation is ongoing as at year end
and is anticipated to continue throughout 2025. It is too early to reliably
estimate the outcome of the investigation and if any prosecution will
eventuate.
Akatara Gas development Change Orders
As part of the final project reconciliation for Akatara, the Group is in
discussions with the Contractor (JGC) concerning change orders raised over the
course of the project. Any final agreement would depend on the assessment of
all contractual obligations, documentation of approved modifications, and
resolution of any outstanding claims from both parties.
45. EVENTS AFTER THE END OF THE REPORTING PERIOD
Redetermination of the borrowing base under the reserves-based lending
facility
On 2 April 2025, the RBL Banks finalised a routine redetermination of the
borrowing base under RBL, with the revised borrowing capacity reduced from
US$200.0 million to US$167.0 million following the sale of Sinphuhorm and the
passing of the Lemang completion test. The reduction in the RBL was made on 17
April 2025 from the cash receipt generated from the sale of Sinphuhorm.
Working Capital facility for US$30.0 million with international bank.
On 10 April 2025, the Group closed a US$30.0 million working capital facility
with international bank with a maturity date of 31 December 2026. The facility
carries a Secured Overnight Financing Rate ("SOFR"), plus 7% margin and was
undrawn at the date of signing the financial statements. The facility, if,
required, may be drawn upon to support general corporate purposes.
Sale of Sinphuhorm for US39.4 million
On 16 April 2024, the Group has divested its 9.52% interest in the producing
Sinphuhorm gas field and Dong Mun discovery onshore Thailand to PTTEP HK
Holding Limited, a subsidiary of PTTEP, Thailand's national oil and gas
company, for a cash consideration of US$39.4 million, with a further US$3.5
million in cash payable contingent on future license extensions.
The US$39.4 million received consists 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 field, which currently expire in 2029
and 2031, respectively.
Change in Board of Directors
On 16 January 2025, the company announced the appointment of David Mendelson
as an independent non-executive director. Mr. Mendelson is a member of the
Board's Remuneration Committee and Governance and Nomination Committee. On
the same day,the Company announced the resignation of Cedric Fontenit as an
independent non-executive director.
46. RELATED PARTY TRANSACTIONS
Placement of additional shares and issue of warrants
On 6 June 2023, the Company completed an equity fundraising, creating an
additional 94,081,826 ordinary shares at GB£0.45 per share, which comprised
of a placing and subscription of 92,312,691 new ordinary shares to existing
and new institutional shareholders and a placing and subscription of 1,769,135
new ordinary shares to the Directors of the Company. Tyrus, the Group's
largest shareholder, has subscribed to 24,883,387 of new ordinary shares under
the equity fundraising for a consideration of US$13.9 million.
The placing and subscription of 1,769,135 new ordinary shares to the Directors
of the Company at that time were as follows:
Number of shares Consideration paid
USD'000
A. Paul Blakeley 336,311 188
Bert-Jaap Dijkstra 71,556 40
Dennis McShane 178,889 100
Iain McLaren 22,222 12
Robert Lambert 111,269 62
Cedric Fontenit 333,333 186
Lisa Stewart 178,889 100
David Neuhauser 447,222 250
Jenifer Thien 89,444 50
1,769,135 988
In support of the equity fundraising in 2023, the Company entered into an up
to US$50.0 million equity underwrite debt facility agreement with Tyrus. The
equity underwrite facility reduced to zero following the total funds raised
from the equity fundraising and the open offer exceeded US$50.0 million. The
Group incurred upfront fee of US$2.15 million and interest of US$27,778 from
the equity underwrite facility in 2023, which was recorded as finance costs in
Note 14. As part of the underwritten placing of additional ordinary shares,
the Company has also entered into a warrant instrument with Tyrus for 30
million ordinary shares at an exercise price of 50 pence per share. The
warrants are exercisable within 36 months from the date of issuance, with an
expiry date of 5 June 2026.
Committed standby working capital facility
On 6 June 2023, the Company entered into a committed standby working capital
facility with Tyrus, the Group's largest shareholder, for a facility size of
up to US$35.0 million. The standby working capital facility was finalised at
US$31.9 million, after deduction of US$3.1 million of excess funds from the
total gross funds of US$53.1 million raised from the equity placing and open
offer. The facility matured on 31 December 2024. The facility bears
interest of 15% on drawn amounts and 5% on undrawn amounts and can be repaid
or cancelled without penalties. The standby working capital facility was not
utilised and remained undrawn as at 31 December 2024.
Compensation of key management personnel
2024 2023
USD'000 USD'000
Short-term benefits 2,526 2,598
Other benefits 181 -
Share-based payments 233 300
Compensation for loss of office 2,464
5,404 2,898*
The total remuneration of key management members (including salaries and
benefits) was US$5.4 million (2023: US$2.9 million) and recognised as part of
the Group's administrative staff costs as disclosed in Note 7.
Compensation of Directors
Short-term benefits((a)) Other benefits((a)) Share-based payments Total compensation
USD'000 USD'000 USD'000 USD'000
2024
A. Paul Blakeley 908 2,543 90 3,541
Bert-Jaap Dijkstra 757 92 132 981
Dennis McShane 39 - - 39
Iain McLaren 48 - - 48
Robert Lambert 24 - - 24
Cedric Fontenit 89 - - 89
Lisa Stewart 25 - - 25
David Neuhauser 80 - - 80
Jenifer Thien 100 - - 100
Joanne Williams 89 - 8 97
Adel Chaouch 157 - - 157
Andrew Fairclough 141 10 3 154
Linda Beal 69 69
Gunter Waldner((b)) - - - -
2,526 2,645 233 5,404
*The change in prior year figures is due to a revised disclosure basis applied
in 2024, whereby only non-executive and executive directors are identified as
key management personnel in accordance with IAS 24 Related Party Disclosures,
with senior management no longer included.
Short-term benefits((a)) Other benefits((a)) Share-based payments Total compensation
USD'000 USD'000 USD'000 USD'000
2023
A. Paul Blakeley 1,093 - 210 1,303
Bert-Jaap Dijkstra 785 - 84 869
Dennis McShane 155 - 1 156
Iain McLaren 105 - 1 106
Robert Lambert 95 - 1 96
Cedric Fontenit 85 - 1 86
Lisa Stewart 100 - 1 101
David Neuhauser 80 - 1 81
Jenifer Thien 100 - - 100
Gunter Waldner((b)) - - - -
2,598 - 300 2,898
( )
((a)) Short-term benefits comprise salary, director fee as applicable,
performance pay, pension and other allowances. Other benefits comprise
benefits-in-kind. Other benefits 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)) 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.
((c)) During the year, A.Paul Blakeley, Bert-Jaap Dijkstra, Dennis McShane,
Ian Mclaren, Robert Lambert and Lisa Stewart stepped down as the directors.
Joanne Williams, Adel Chaouch, Andrew Fairclough and Linda Beal were appointed
during the year.
Company Statement of Financial Position as at 31 December 2024
2024 2023
Notes USD'000 USD'000
Assets
Non-current assets
Investment in subsidiaries 5 28,005 27,598
Loan to a subsidiary 7 214,579 217,112
Total non-current asset 242,584 244,710
Current assets
Amount owing by subsidiaries 128,776 105,875
Prepayments 30 1,910
Cash and cash equivalents 979 56,588
Total current assets 129,785 164,373
Total assets 372,369 409,083
Equity and liabilities
Equity
Capital and reserves
Share capital 8 457 456
Share premium account 8 52,176 51,827
Merger reserve 10 61,068 61,068
Share-based payment reserve 11 27,730 27,673
Capital redemption reserve 24 24
Retained earnings 228,575 235,842
Total equity 370,030 376,890
2024 2023
Notes USD'000 USD'000
Liabilities
Current liabilities
Other payables and accruals 12 1,408 1,455
Amount owing to a subsidiary - 27,269
Warrant liability 13 931 3,469
Total current liabilities 2,339 32,193
Total liabilities 2,339 32,193
Total equity and liabilities 372,369 409,083
During the year, the Company made a loss after tax of US$7.3 million (2023:
US$4.9 million profit after tax).
Company Statement of Changes in Equity for the year ended 31 December 2024
Share premium Capital redemption reserve Share-based payments reserve
Share capital account USD'000 USD'000 Merger reserve Retained earnings
USD'000 USD'000 USD'000 USD'000 Total
USD'000
As at 1 January 2023 339 983 21 26,907 61,068 232,984 322,302
Share-based compensation:
Company - - - 6 - - 6
Subsidiaries - - - 760 - - 760
Shares issued (Note 8) 120 52,846 - - - - 52,966
Transaction costs associated with issuance of - (2,002) - - - - (2,002)
shares (Note 29)
Shares repurchased (Note 8) (3) - 3 - - (2,084) (2,084)
Total transactions with owners 117 50,844 3 766 - (2,084) 49,646
Profit and total comprehensive income for the year - - - - - 4,942 4,942
As at 31 December 2023 and 1 January 2024 456 51,827 24 27,673 61,068 235,842 376,890
Share-based compensation:
Company - - - - - - -
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 457 52,176 24 27,730 61,068 228,575 370,030
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 6th Floor is 60
Gracechurch Street, London, EC3V 0HR 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 recognised 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 recognised 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 realisation of the loan, including the past collection history
from Jadestone Energy Holdings Ltd ("JEHL") plus estimation of the future
profitability of JEHL, with its sole source of income being dividend income to
be received from JEHL's subsidiaries. Accordingly, the Directors exercised
judgement in estimating the future profitability of the oil and gas operations
held by the JEHL's subsidiaries.
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.
5. INVESTMENT IN SUBSIDIARY
2024 2023
USD'000 USD'000
Unquoted share, at cost -* -*
Share-based payment:
At beginning of year 27,598 26,838
Share-based compensation at subsidiaries during the year 407 760
At end of year 28,005 27,598
28,005 27,598
* Rounded to the nearest thousand.
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 2024 % voting
rights and ordinary shares held 2023
Nature of business
Direct
Jadestone Energy Holdings Ltd ((1)) England and Wales 100 100 Investment
holdings
Indirect
Jadestone Energy (Australia) Pty Ltd Australia 100 100 Production of oil &
( (2)) gas
Jadestone Energy (Australia Australia 100 100 Investment
Holdings) Pty Ltd ((2)) 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 (Lemang) Pte Ltd Singapore 100 100 Exploration
( (4))
Jadestone Energy Ltd ((5)) Bermuda 100 100 Investment
holdings
Jadestone Energy (Malaysia) Pte Ltd Singapore 100 100 Production of oil &
( (4)) gas
Jadestone Energy (PHT GP) Limited England and Wales 100 100 Investment
( (1)) holdings
Name of the company Place of incorporation % voting rights and ordinary shares held 2024 % voting
rights and ordinary shares held 2023
Nature of business
Jadestone Energy (PM) Inc. ((6)) Bahamas 100 100 Production of oil &
gas
Jadestone Energy Pte Ltd ((4)) Singapore 100 100 Investment holdings
Jadestone Energy (Singapore) Pte Singapore 100 100 Investment
Ltd ((4)) holdings
Jadestone Energy Sdn Bhd ((7)) Malaysia 100 100 Administration
Jadestone Energy (Thailand) Pte Ltd Singapore 100 100 Investment
( (4)) holdings
Jadestone Energy UK Services Ltd ((1)) England and Wales 100 100 Administration
Mitra Energy (Philippines SC- 56) Ltd Bermuda 100 100 Exploration
( (5))((a))
Mitra Energy (Vietnam Nam Du) Pte Singapore 100 100 Exploration
Ltd ((4))
Mitra Energy (Vietnam Tho Chu) Pte Singapore 100 100 Exploration
Ltd ((4))
PHT Partners LP ((8)) Delaware 100 100 Investment
holdings
Registered office addresses:
(1) 6th Floor, 60 Gracechurch Street, London, EC3V 0HR 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 Anson Road #13-01, Springleaf Tower, Singapore 079909
(5) 3rd Floor - Par la Ville Place, 14 Par la Ville Road, Hamilton HM08,
Bermuda
(6) H&J Corporate Services Ltd, Ocean Centre, Montagu Foreshore, East bay
Street, P.O. Box N-3247, Nassau, Bahamas
(7) Level 15-2, Bangunan Imperial Court, Jalan Sultan Ismail, 50250, Kuala
Lumpur, Malaysia
(8) CT Corporation, 1209 Orange St, Wilmington, DE 19801, United States
(a) Mitra Energy (Philippines SC-56) Ltd was dissolved on 31 December 2024.
6. STAFF NUMBER AND COSTS
The Company had no employee in 2024. In 2023, the Company had one employee at
the beginning of 2023, then the employee was transferred to a subsidiary
during the year of 2023.
The aggregate remuneration comprised:
2024 2023
USD'000 USD'000
Wages and salaries - 9
Non-executive director's fee 701 764
701 773*
* In 2024, the amount of non-executive directors' fees has been disclosed
under staff costs by management. Accordingly, US$0.8 million relating to 2023
has also been disclosed for comparative purposes.
7. RELATED PARTY TRANSACTIONS
The Company did not enter into new loan with its subsidiary during the year
Amount owing by subsidiaries are mainly related to payments on behalf, and a
receipt on behalf of the Company by a subsidiary for the proceeds from
issuance of shares during the period. 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:
2024 2023
USD'000 USD'000
Loan to a subsidiary
At the beginning of the year 217,112 252,485
Repayment during the year - (52,865)
Unrealised foreign exchange differences (2,533) 17,492
Total transaction during the year 214,579 217,112
Subsidiaries
Advances 12,056 41,608
Repayment received - (33,583)
Payment on behalf by 39,289 65,328
Repayment made (1,175) 7,525
Total transaction during the year 50,170 80,878
Placement of additional shares and issue of warrants
On 6 June 2023, the Company completed an equity fundraising, creating an
additional 94,081,826 ordinary shares at GB£0.45 per share, which comprised
of a placing and subscription of 92,312,691 new ordinary shares to existing
and new institutional shareholders and a placing and subscription of 1,769,135
new ordinary shares to the Directors of the Company. Tyrus, the Company's
largest shareholder, subscribed to 24,883,387 of new ordinary shares under the
equity fundraising for a consideration of US$13.9 million.
The placing and subscription of 1,769,135 new ordinary shares to the Directors
of the Company at that time were as follows:
Number of shares Consideration paid
USD'000
A. Paul Blakeley 336,311 188
Bert-Jaap Dijkstra 71,556 40
Dennis McShane 178,889 100
Iain McLaren 22,222 12
Robert Lambert 111,269 62
Cedric Fontenit 333,333 186
Lisa Stewart 178,889 100
David Neuhauser 447,222 250
Jenifer Thien 89,444 50
1,769,135 988
In support of the equity fundraising in 2023, the Company entered into an up
to US$50.0 million equity underwrite debt facility agreement with Tyrus. The
equity underwrite facility reduced to zero following the total funds raised
from the equity fundraising and the open offer exceeded US$50.0 million. The
Group incurred upfront fee of US$2.15 million and interest of US$27,778 from
the equity underwrite facility in 2023, which was recorded as finance costs in
Note 14 of the consolidated financial statements. As part of the underwritten
placing of additional ordinary shares, the Company has also entered into a
warrant instrument with Tyrus for 30 million ordinary shares at an exercise
price of 50 pence per share. The warrants are exercisable within 36 months
from the date of issuance, with an expiry date of 5 June 2026 as disclosed in
Note 41 to the consolidated financial statements.
Committed standby working capital facility
On 6 June 2023, the Company entered into a committed standby working capital
facility with Tyrus, the Company's largest shareholder, for a facility size of
up to US$35.0 million. The standby working capital facility was finalised at
US$31.9 million, after deduction of US$3.1 million of excess funds from the
total gross funds of US$53.1 million raised from the equity placing and open
offer. The facility matured on 31 December 2024. The facility bears
interest of 15% on drawn amounts and 5% on undrawn amounts and can be repaid
or cancelled without penalties. The standby working capital facility was not
utilised and remained undrawn as at 31 December 2024.
For the year ended 31 December 2024, the Company had incurred interest expense
of US$2.4 million (2023: US$3.6 million), which was recorded as finance costs
in Note 14 of the consolidated financial statements.
8. SHARE CAPITAL AND SHARE PREMIUM ACCOUNT
Share capital Share premium account
No. of shares USD'000 USD'000
Issued and fully paid
As at 1 January 2023, at £0.001 each 448,363,663 339 983
Issued during the year 94,463,933 120 50,844
Share repurchases (2,051,022) (3) -
As at 31 December 2023 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
On 19 January 2023, the Company suspended its share buyback programme. As at
31 December 2023, the Company had acquired 2.3 million shares at a weighted
average cost of GB£0.75 per share, resulting in total expenditure of US$2.1
million. The total nominal value of the shares repurchased was US$2,485.
All shares repurchased were cancelled. Since the launch of the share buyback
programme, a total of 20.4 million shares had been acquired for a total
accumulated expenditure of US$18.1 million, total nominal value of the shares
repurchased was US$23,778.
On 6 June 2023, the Company completed an equity fundraising, creating an
additional 94,081,826 ordinary shares at GB£0.45 per share, which comprised
of a placing and subscription of 92,312,691 new ordinary shares to existing
and new institutional shareholders and a placing and subscription of 1,769,135
new ordinary shares to the Directors of the Company. Total gross proceeds were
US$53.0 million, with net proceeds of US$51.0 million. The Group incurred
total costs of US$2.0 million associated with the equity fundraising and these
costs were accounted as a deduction to the equity.
On 9 June 2023, the Company launched an open offer of up to 14,887,039 new
ordinary shares, at GB£0.45 per share, to raise additional proceeds of up to
EUR8.0 million 22 (up to US$8.6 million). The open offer closed on 28 June
2023, raising a total of US$42,009 by issuing 73,557 new shares.
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.
During the year, no employee share options were exercised and issued (2023:
128,160 shares; GB£0.56 per share). Additionally, no shares (2023: 79,327
shares) were issued during the year to satisfy the Company's obligations with
regards to the performance shares and 344,225 shares (2023: 101,063 shares)
were issued to meet the obligations with regards to the restricted shares.
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 reorganisation in 2021.
11. SHARE-BASED PAYMENTS RESERVE
Share-based payments reserve represents the cumulative value of share-based
payment expenses recognised 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$0.4 million (2023:
US$0.8 million) was recognised as 'administrative staff costs' (Note 7) in
profit or loss for the year ended 31 December 2024.
During the year, 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 29 to the consolidated financial statements.
The share-based payment expense arose from share options, performance shares
and restricted shares 23 (#_ftn23) awarded from 2020 to 2022. The
performance share grants were suspended in 2023 by the Remuneration Committee
in view of the performance of the Group in 2023. In consultation with an
external advisor, the Remuneration Committee approved a Deferred Cash Plan
("DCP") for the 2023 - 2026 Long-Term Incentive ("LTI") cycle, which was
awarded in October 2023 (Note 39). 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.
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.
10.1 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
9 March 2022
Risk-free rate 1.34% to 1.38%
Expected life 5.5 to 6.5 years
Expected volatility 24 63.0% to 66.7%
Share price GB£ 1.01
Exercise price GB£ 0.92
Expected dividends 1.96%
10.2 Performance shares
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).
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
9 March 2022
Risk-free rate 1.39%
Expected volatility 25 53.1%
Share price GB£ 1.01
Exercise price N/A
Expected dividends 1.71%
Post-vesting withdrawal date N/A
Early exercise assumption N/A
10.3 Restricted shares 26
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
22 August 2022 9 March 2022
Risk-free rate 1.73% 1.39%
Share price GB£ 0.90 GB£ 1.01
Expected dividends 1.73% 1.71%
The following table summarises the options/shares under the LTI plans
outstanding and exercisable as at 31 December 2024:
Shares 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 2023 2,745,943 445,288 19,738,936 0.45 7.15 12,316,331
Vested during the (79,327) (101,063) - 0.44 6.32 4,665,000
year
Exercised during the - - (128,160) 0.56 - (128,160)
year
Expired unexercised (449,513) - - - - -
during the year
Cancelled during the - - (344,655) 0.60 - (344,655)
year
As at 31 December 2,217,103 344,225 19,266,121 0.48 5.37 16,508,516
2023
Vested during the - (344,225) 0.76 7.19 2,118,585
year
Expired unexercised (967,794) - (125,418) 0.59 - (125,418)
during the year
Granted during the - 1,242,000 - - - -
year
As at 31 December 1,249,309 1,242,000 19,140,703 0.45 4.67 18,501,683
2024
The weighted average share price on the exercise date in 2023 is GB£0.83.
Range of Weighted average Weighted
exercise exercise average
Number of options price price GB£ remaining
GB£ contract life
Share options exercisable as at 31 December 2023 16,508,516 0.26 - 0.99 0.41 4.92
Share options exercisable as at 31 December 2024 18,501,683 0.26- 0.99 0.45 4.67
12. OTHER PAYABLES
2024 2023
USD'000 USD'000
Other payables 938 563
Accruals 470 892
1,408 1,455
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 2024, the fair value of warrant liability
was US$0.9 million (2023: US$3.5 million). The differences of the fair value
of warrants liability of US$2.5 million as disclosed in Note 15 to the
consolidated financial statements.
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:
2024 2023
Risk-free rate 4.48% 3.77%
Expected life 1.4 years 2.5 years
Expected volatility 27 59.5% 54.5%
Share price GB£ 0.24 GB£ 0.37
Exercise price GB£ 0.50 GB£ 0.50
Expected dividends 0% 0%
14. EVENTS AFTER THE END OF REPORTING PERIOD
Redetermination of the borrowing base under the reserves-based lending
facility
On 2 April 2025, the RBL Banks finalised a routine redetermination of the
borrowing base under RBL, with the revised borrowing capacity reduced from
US$200.0 million to US$167.0 million following the sale of Sinphuhorm and the
passing of the Lemang completion test. The reduction in the RBL was made on 17
April 2025 from the cash receipt generated from the sale of Sinphuhorm.
Working Capital facility for US$30.0 million with international bank.
On 10 April 2025, the Group closed a US$30.0 million working capital facility
with international bank with a maturity date of 31 December 2026. The facility
carries a Secured Overnight Financing Rate ("SOFR"), plus 7% margin and was
undrawn at the date of signing the financial statements. The facility, if,
required, may be drawn upon to support general corporate purposes.
Sale of Sinphuhorm for US39.4 million
On 16 April 2024, the Group has divested its 9.52% interest in the producing
Sinphuhorm gas field and Dong Mun discovery onshore Thailand to PTTEP HK
Holding Limited, a subsidiary of PTTEP, Thailand's national oil and gas
company, for a cash consideration of US$39.4 million, with a further US$3.5
million in cash payable contingent on future license extensions.
The US$39.4 million received consists 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 field, which currently expire in 2029
and 2031, respectively.
Change in Board of Directors
On 16 January 2025, the company announced the appointment of David Mendelson
as an independent non-executive director. Mr. Mendelson is a member of the
Board's Remuneration Committee and Governance and Nomination Committee. On
the same day,the Company announced the resignation of Cedric Fontenit as an
independent non-executive director.
GLOSSARY
1P reserves those reserves with 90% probability of quantities actually recovered being
equal or greater to the sum of estimated proved reserves
2P reserves 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
2C resources best estimate contingent resource
AGPF Akatara Gas Processing Facility
AIM Alternative Investment Market
ARO asset retirement obligations
bbl barrel
bbls/d barrels per day
bcf billion standard cubic feet
the Board the board of directors of Jadestone Energy plc.
boe barrels of oil equivalent
boe/d barrels of oil equivalent per day
CALM catenary anchor leg mooring
CEO chief executive officer
CFO chief financial officer
CO(2)-e carbon dioxide equivalent
the Company Jadestone Energy plc
CWLH Cossack, Wanaea, Lambert and Hermes oil fields offshore Australia
DD&A depletion, depreciation and amortization
EBITDAX earnings before interest tax, depreciation, amortization and exploration
EPCI engineering, procurement, construction and installation
ESG Environment, Social and Governance
FOB free on board, a commercial structure for selling oil, where the buyer takes
responsibility for the cargo and transportation costs after loading onto an
offtake tanker
FPSO floating production storage and offloading
GHG greenhouse gases
the Group Jadestone Energy plc and its subsidiaries
GSPA gas sales and purchase agreement
IEA the International Energy Agency
IFRS International Financial Reporting Standards
LPG liquefied petroleum gas
LTI lost-time injury
mcf thousand standard cubic feet of natural gas
mm million
mmbbls million barrels
mmboe million barrels of oil equivalent
mmcf/d million standard cubic feet per day
mmcf million standard cubic feet
NDUM Nam Du and U Minh gas fields offshore Vietnam
opex operating expenditures
PenMal Assets collectively, Jadestone's Peninsular Malaysia assets
PETRONAS Petroliam Nasional Berhad
PITA Malaysia Petroleum Income Tax
PNLP Assets collectively, a number of oil fields offshore Peninsular Malaysia in which
Jadestone acquired a non-operated interest as part of its wider Peninsular
Malaysia entry in 2021. These assets, originally known as the PM318/AAKBNLP
PSCs, were renamed the PNLP Assets after Jadestone assumed operatorship of the
licenses in April 2023 following the withdrawal of the previous operator.
Certain of the PNLP Assets were included in the Malaysia Bid Round Plus, with
Jadestone subsequently being awarded a 100% interest in the Puteri Cluster in
2024.
PRRT Petroleum Resource Rent Tax
PSC production sharing contract
QCA Code Quoted Companies Alliance Corporate Governance Code, a set of principles
designed to promote good corporate governance practices among small and
mid-sized companies, particularly those listed on the AIM market in the UK
R&M repairs and maintenance
RBL Facility the Group's US$200 million reserves-based lending facility closed in May 2023
with a four-year tenor
reserves hydrocarbon resource that is anticipated to be commercially recovered from
known accumulations from a given date forward
resources being quantities of hydrocarbons which are estimated, on a given date, to be
potentially recoverable from known accumulations but which are not currently
considered to be commercially recoverable
ROV remote operated vehicle
US$ United States dollar
The technical information in this announcement has been prepared in accordance
with the June 2018 Society of Petroleum Engineers, World Petroleum Congress,
American Association of Petroleum Geologists and Society of Petroleum
Evaluation Engineers Petroleum Resource Management System ("PRMS") as the
standard for classification and reporting.
A. Shahbaz Sikandar of Jadestone Energy plc, Group Subsurface Manager with a
Masters degree in Petroleum Engineering, and who is a member of the Society of
Petroleum Engineers and has worked in the energy industry for more than 25
years, has read and approved the technical disclosure in this regulatory
announcement.
The information contained within this announcement is considered to be inside
information prior to its release, as defined in Article 7 of the Market Abuse
Regulation No. 596/2014 which is part of UK law by virtue of the European
Union (Withdrawal) Act 2018, and is disclosed in accordance with the Company's
obligations under Article 17 of those Regulations.
1 Based on a Brent oil price range of US$70-80/bbl (real terms from 2025).
Assumes midpoint of internal production expectations and that all barrels
produced during 2025-27 are sold in the period. Does not reflect any capital
expenditure or abandonment spend outside the Group's producing assets.
Reflects upfront consideration from the sale of the Group's assets in Thailand
on 16 April 2025.
2 2023 Scope 1 emissions have been restated due to a flare meter
configuration issue at Stag which resulted in historical flaring volumes and
GHG emissions to be underreported.
3 Effective capacity may be less depending on operational factors and
conditions.
4 The local government has an option to take a 10% participating interest in
the Lemang PSC, which, if exercised, would reduce Jadestone's working interest
to 90%.
5 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.
6 The closing adjustment represents the economic benefits of production
since the effective date and completion.
7 Malaysia Petroleum Management ("MPM") is entrusted to act for and on
behalf of PETRONAS in the overall management of Malaysia's petroleum
resources.
8 The offset of the deferred tax liabilities and deferred tax assets are
withing respective tax jurisdiction.
9 Restricted shares are granted to eligible employees and directors, subject
to vesting conditions. Upon vesting, the shares are transferred directly to
recipients and recognised in share capital.
10 The open offer was quoted in Euro of 8.0 million to meet the applicable
regulation issued by the European Union regarding to the quantum of open
offer.
11 Restricted shares are granted to eligible employees and directors,
subject to vesting conditions. Upon vesting, the shares are transferred
directly to recipients and recognised in share capital.
12 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.
13 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.
14 Restricted shares are granted to eligible employees and directors,
subject to vesting conditions. Upon vesting, the shares are transferred
directly to recipients and recognised in share capital.
15 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.
16 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.
17 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.
18 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.
19 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.
20 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.
21 The borrowings of US$200.2 million (2023: US$154.6 million) represents
the fair value of the balance. The gross outstanding balance as at 31
December 2024 is US$200.0 million (2023: US$157.0 million).
22 The open offer was quoted in Euro of 8.0 million to meet the applicable
regulation issued by the European Union regarding to the quantum of open
offer.
23 Restricted shares are granted to eligible employees and directors,
subject to vesting conditions. Upon vesting, the shares are transferred
directly to recipients and recognised in share capital.
24 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.
25 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.
26 Restricted shares are granted to eligible employees and directors,
subject to vesting conditions. Upon vesting, the shares are transferred
directly to recipients and recognised in share capital.
27 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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