REG - Jadestone Energy PLC - 2024 Half Year Results
17/09/2024 07:15
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RNS Number : 4811E Jadestone Energy PLC 17 September 2024
2024 Half Year Results
17 September 2024-Singapore: Jadestone Energy plc (AIM:JSE) ("Jadestone" or
the "Company"), an independent oil and gas production company and its
subsidiaries (the "Group"), focused on the Asia-Pacific region, reports its
unaudited condensed consolidated interim financial statements, as at and for
the six-month period ended 30 June 2024 (the "financial statements").
Management will host a webcast at 9:00 a.m. UK time today, details of which
can be found in the announcement below.
Key updates:
l Akatara development project achieved mechanical completion in June 2024,
with sales gas production commencing in July 2024 and reaching c.14mmscf/d.
Production has been recently curtailed by a small mechanical issue in the gas
processing facility's refrigeration compressors, with repairs underway. These
repairs and their associated cost remain the responsibility of the EPCI
contractor.
l Positive progress on the Montara oil storage tank repair and maintenance
programme, which has allowed for the permanent stationing of shuttle tanker at
the field to be discontinued in late-August, earlier than expected.
l Year-to date 2024 production (to end August 2024) has averaged c.17,500
boe/d, a c.42% increase year-on-year due to the success of both organic and
acquisition driven growth over the period. Annual 2024 production guidance is
reiterated at 18,500 - 21,000 boe/d, with an expected outcome towards the
lower end of the range, given year-to-date production and ongoing Akatara
activities.
l Operating expenditure guidance for 2024 is reiterated at US$240-280 million
(excluding forecast royalties and carbon taxes of c.US$30 million),
l Capital expenditure and other cash expenditure guidance is unchanged at
US$80-110 million and US$62 million respectively,
l US$31.1 million loss after tax for the first half of 2024, which includes a
US$45.8 million non-cash charge to production costs related to the CWLH 2
acquisition, which closed in February 2024.
l Net debt of US$69.1 million at 30 June 2024 reflects c.US$130.9 million of
consolidated Group cash balances and US$200.0 million of debt drawn under the
Group's reserves-based lending ("RBL") facility. As at 31 August 2024, net
debt was US$94.6 million, based on consolidated Group cash balances of
US$105.4 million and US$200.0 million of debt drawn under the RBL facility.
The Group expects to receive c.US$57 million of proceeds in September relating
to August liftings. The Group's US$31.9 million working capital facility was
undrawn at the end of the period.
Paul Blakeley, President and CEO commented:
"Increased production, coupled with robust price realisations and flat
underlying operating costs, resulted in an improving financial performance in
the first half of 2024, with adjusted EBITDAX and operating cash flows
significantly higher year-on-year.
Our first half performance also benefited from the increasing diversification
of the portfolio as we build greater reliability and resilience. The adverse
weather which impacted our Australia production early in the year was offset
by higher production from Malaysia, an increase in our CWLH interest and
strong output from Sinphuhorm. Montara performance continues to improve with
greater facility reliability year-to-date, and good progress on the FPSO tank
and repair programme, which allowed us to release the temporary storage tanker
at Montara a few months earlier than planned. We also added a medium-term
growth option by signing the SFA Cluster PSC offshore Malaysia, and we
continue to work hard on a gas sales agreement for our Vietnam resource.
Jadestone's primary focus so far in 2024 has been the completion and
commissioning of the Akatara development project onshore Indonesia. The
construction phase was completed on schedule at the end of the second quarter,
followed by the start of both gas and condensate sales. Notwithstanding the
current curtailment of production for a repair to the plant's refrigeration
compressors, the progress at Akatara, including an excellent safety record, is
a major step forward for the Group, and will diversify our cash flow
generation with more low cost and high value production."
2024 FIRST HALF RESULTS SUMMARY
USD'000 except where indicated Six months Six months Twelve months ended 31 December 2023
ended ended
30 June 30 June
2024 2023
Total hours worked lost time injury free (million) 3.85 1.45 4.55
Total recordable injury rate 3.12 0.00 0.86
Production, boe/day(1) 16,867 12,339 13,813
Realised oil price per barrel of oil equivalent (US$/boe)(2) 88.73 86.15 87.34
Realised gas price per thousand standard cubic feet 1.64 1.41 1.53
(US$/mscf)
Revenue(3) 185,060 86,660 309,200
Production costs (136,324) (90,650) (232,772)
Adjusted unit operating costs per barrel of oil equivalent 31.72 40.27 37.24
(US$/boe)(4)
Adjusted EBITDAX(4) 60,215 (3,127) 90,647
Loss after tax (31,119) (59,934) (91,274)
Loss per ordinary share: basic and diluted (US$) (0.06) (0.13) (0.18)
Operating cash flows before movement in working capital 27,946 (24,179) 36,499
Capital expenditure 47,618 23,807 115,882
Net (debt)/cash(4) (69,131) 7,782 (3,596)
Operational and financial summary
l Zero lost time injuries in operated and non-operated assets. This involved
working 3.85 million manhours in operated assets (H1 2023: 1.45 million
manhours), an increase of 165% from H1 2023.
l Zero Tier 1 or Tier 2 process safety events, with a focus on pre
commissioning activities at Akatara and ongoing asset integrity programs at
operated assets.
l Production increased by 37% in H1 2024, reaching 16,867 boe/d, up from
12,339 boe/d in H1 2023. The increase was due to higher production from PenMal
following the successful drilling campaign in late 2023, a higher working
interest in the CWLH following completion of the acquisition of an additional
16.67% working interest in February 2024, full production from Sinphuhorm,
acquired in February 2023, and a full period of production from Montara,
compared to H1 2023 when production was shut in for much of the first quarter.
These increases were partially offset by lower production at Stag compared to
the prior period, impacted by extensive weather-related downtime in Q1 2024, a
planned maintenance shutdown and underperformance of downhole pumps, which
have required more frequent workovers than planned.
l Oil liftings totaled 2.2 mmbbls in H1 2024, more than double H1 2023 of 1.1
mmbbls, primarily driven by increased production described above and the
addition of an underlift position at CWLH as part of the February 2024
acquisition, which subsequently formed part of a lifting in March 2024.
l The average oil price realisation, excluding the effect of hedging for H1
2024, was US$88.73/bbl, a 3.0% increase from US$86.15/bbl in H1 2023. This
increase was driven by a higher realised Brent price, which rose by 8.9%, to
US$84.14/bbl from US$77.28/bbl in H1 2023. The higher realised Brent price was
offset by a reduction in the premium to US$4.59/bbl in H1 2024, from
US$8.87/bbl in H1 2023. This decrease was due to the composition of liftings,
with lower liftings at Stag (which attracts the highest premium of Jadestone's
production), and higher lifted volumes at CWLH, which has a lower premium.
l H1 2024 revenue totalled US$185.1 million, a 113% increase on H1 2023,
reflecting the increase in lifted volumes and price realisations described
above. H1 2024 revenue reflects a hedging charge of US$15.4 million from
commodity swap contracts entered in support of the execution of reserves-based
lending ("RBL") facility;
l The CWLH 2 acquisition impacted revenues and production costs in H1 2024 by
US$45.8 million (2023: Nil), reflecting the market value of the under-lift
obtained after acquiring an additional 16.67% interest in the CWLH assets
(combined interest 33.34%) in February 2024. The US$45.8 million in production
costs is a non-cash item arising from the purchase price allocation required
under acquisition accounting standards. The underlift was sold as part of the
March 2024 lifting realising US$45.8 million.
l Production costs, excluding the movement in inventory and the under-lift
impacts, decreased by 0.7%, from US$116.4 million in H1 2023 to US$115.5
million in H1 2024.
l As at 30 June 2024, closing crude inventories totalled 442,781 bbls, and the
Group had an underlift position of 270,449 bbls. After the H1 2024 reporting
period, the Group generated US$53.0 million in revenues from three liftings of
0.59 mmbbls in July from Montara, Stag and PenMal;
l Adjusted EBITDAX increased to US$60.2 million from a loss of US$3.2 million
in H1 2023, mostly due to higher revenue;
l Net loss after tax in H1 2024 of US$31.1 million (H1 2023: US$59.9 million
net loss);
l Operating cash flow before movements in working capital significantly
improved in H1 2024 to US$27.9 million from an outflow of US$24.2 million in
H1 2023, reflecting the trends described above;
l Capital expenditure in H1 2024 of US$47.6 million, an increase of 100%
compared to H1 2023 (at US$23.8 million) primarily due to higher expenditure
for the Akatara development project onshore Indonesia as it entered the final
phase of commission and completion; and
l Net debt balance of US$69.1 million as at 30 June 2024 (H1 2023: US$7.8
million net cash), reflecting a drawdown of US$200.0 million from the RBL
facility and total cash and cash equivalents of US$130.9 million.
(1) Production includes the Sinphuhorm Asset gas production in accordance with
Petroleum Resource Management Systems guidelines, non-IFRS measures. However,
in accordance with IAS 28 the investment is accounted for as an associated
undertaking and only recognises the share of results of associate.
Accordingly, the revenue and production costs from the Sinphuhorm Assets are
excluded from the Group's financial results. Sinphuhorm production is included
in the Group's production figures.
(2) Realised oil price represents the actual selling price inclusive of
premiums, excluding the effect of hedging.
(3)Revenue in H1 2024 and YE 2023 include hedging loss of US$15.4 million and
US$10.3 million respectively from the commodity swap contracts entered into in
support of 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 on the
Non-IFRS Measures section in this document.
For further information, please contact:
Jadestone Energy plc
Paul Blakeley, President and CEO +65 6324 0359 (Singapore)
Bert-Jaap Dijkstra, CFO
Phil Corbett, Head of Investor Relations +44 (0) 7713 687467 (UK)
ir@jadestone-energy.com (mailto:ir@jadestone-energy.com)
Stifel Nicolaus Europe Limited (Nomad, Joint Broker) +44 (0) 20 7710 7600 (UK)
Callum Stewart
Jason Grossman
Ashton Clanfield
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 jse@camarco.co.uk (mailto:jse@camarco.co.uk)
Georgia Edmonds
Elfie Kent
Webcast
The Company will host an investor and analyst presentation at 9:00 a.m. (BST)
on Tuesday, 17 September 2024, including a question-and-answer session,
accessible through the link below:
Webcast link:
https://www.investis-live.com/jadestone-energy/66c5c57a7caa6c19003474c9/maert
(https://apc01.safelinks.protection.outlook.com/?url=https%3A%2F%2Fwww.investis-live.com%2Fjadestone-energy%2F66c5c57a7caa6c19003474c9%2Fmaert&data=05%7C02%7Cpcorbett%40jadestone-energy.com%7C344c076d27d04ec9944e08dcc1dd8808%7C05c124ff37ea4b96b46f7764de1d4f38%7C1%7C0%7C638598404523439481%7CUnknown%7CTWFpbGZsb3d8eyJWIjoiMC4wLjAwMDAiLCJQIjoiV2luMzIiLCJBTiI6Ik1haWwiLCJXVCI6Mn0%3D%7C0%7C%7C%7C&sdata=cJxfTDLSnxcWvPoAMIbkpiHJiOOKw9QvrQ8ergqmfrI%3D&reserved=0)
Event title: Jadestone Energy plc first-half 2024 results
Time: 9:00 a.m. (BST)
Date: 17 September 2024
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=54821)
Access Code: 288973
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, whilst
bringing positive social and economic benefits for its stakeholders, local
communities and the people associated with its operations. Progress made
during the half year ended 30 June 2024 is set out below across Jadestone's
priority ESG areas.
HSE Governance
The Group continued its strong safety performance in the first year half of
2024 despite elevated levels of activity at the Akatara project. The Group
reported no life altering events or significant impact to the environment, no
regulatory enforcements notices, no Tier 1 or 2 process safety loss of primary
containment events but one lost time injury (LTI). Jadestone's combined
operations worked over 3.8 million manhours in H1 2024. The lost time injury
related to staff sustaining a shoulder injury which required minor surgery.
Of note is the safety record at the Akatara gas development project site
onshore Sumatra, Indonesia, which achieved the major milestones of mechanical
completion and introduction of feed gas from wells, which signalled the
commencement of commissioning activities in June 2024. The project has
achieved 7.4 million manhours with no LTI reported. Commissioning saw the site
transition from a construction site to a facility producing hydrocarbons,
requiring a change in how work is planned and executed. As at the end of
June, there had been no process safety loss of primary containment events
associated with commissioning, with ongoing activities to ensure controls are
effectively implemented. Whilst the site currently remains formally under the
control of the EPCI contractor, a detailed Operational Readiness program has
been undertaken by the Company to ensure that when the performance test is
completed, and the facility is formally handed over, Jadestone Energy is ready
to safely operate the facility.
The Montara Venture FPSO tank inspection and repair program has been
progressing well, following a Prohibition Notice issued by the regulator in
June 2022. All tanks have been inspected and repairs are ongoing. Jadestone
continues to engage closely and transparently with the regulator about the
progress of the inspection and repair work and as each tank is completed, a
Technical File Note is issued to the regulator which allows the tank to be
released from the Prohibition Notice.
Net Zero interim targets
Jadestone's strategy for maximising reserves from existing producing oil and
gas fields explicitly precludes frontier exploration and new greenfield
development, a position that is in line with the IEA's Net Zero Emissions by
2050 Scenario. The Group is well positioned to remain relevant in the face of
energy transition as a responsible steward of mid-life assets divested by
larger companies, committed to upholding climate targets and executing its Net
Zero by 2040 pledge.
The Company is committed to reduce Scope 1 and 2 absolute GHG emissions from
its operated assets by 20% by 2026 and by 45% by 2030 (from 2021 levels) on
its pathway to Net Zero by 2040. These interim targets will be achieved
through a combination of measures, including minimising flaring, methane
quantification, monitoring and reduction as well as reliance on carbon credits
within the regulatory schemes of Jadestone's operating regions. For details of
Jadestone's Net Zero GHG reduction plan, please refer to the 2023
Sustainability Report.
Group's H1 2024 Scope 1 GHG emissions(1) during H1 2024 were slightly below
plan, due to operations at Stag being affected by monsoon activity and flaring
reduction initiatives at Montara. At the Montara site, a 33% reduction on
flaring emissions compared to workplan and budget was achieved in H1 2024, due
to a heightened focus on minimisation of flaring during normal production as
part of a three-step flare optimisation plan for Montara. This plan involves:
(1) Includes Montara, Stag and PenMal sites; Jadestone will integrate GHG
emissions from the Akatara Gas field operations in the Full Year 2024 report.
· Reinjection compressor ("RIC") control logic modifications and
automation of the injection choke, with the scope completed in May 2024,
resulting in historically low flare rates post completion;
· Continued focus on reliability of the RIC resulting in
significant improvement in RIC uptime during H1 2024;
· Feasibility analysis into increasing the capacity of the RIC. The
engineering studies have commenced and will be completed during H2 2024.
These initiatives are an important cornerstone of Jadestone's Net Zero
implementation roadmap to 2030.
The Company continues to build a fit-for-purpose Leak Detection and Repair
programme across all operated assets and targets the introduction of annual
leak detection and repair ("LDAR") at each operated site by the end of
2024(1).
Governance
Jadestone's Board underwent a number of changes during the first quarter of
2024, with the longer-term objective to ensure that the Board is sized
appropriate to the Company's scale and ambition, while maintaining the right
capabilities and adhering to corporate governance standards.
On 25 January 2024, the Company announced the appointment of Joanne Williams
as an independent non-executive director. Ms. Williams is the Chair of both
the HSEC Committee and the Montara Technical Committee, and a member of the
Audit Committee and the Disclosure Committee.
On 25 March 2024, the Company announced the appointment of Adel Chaouch as an
independent non-executive director. On the same day, the Company announced the
resignation of Lisa Stewart as an independent non-executive director and
Robert Lambert as an independent non-executive director.
On 27 March 2024, the Company announced the resignation of Dennis McShane as
an independent non-executive director and Chair of the Board. On the same
day, the Company announced the election of Adel Chaouch as the Chairman of the
Board. Mr. Chaouch is the Chairman of the Governance and Nomination Committee,
and a member of the Remuneration Committee.
On 9 May 2024, the Company announced the appointment of Linda Beal as an
independent non-executive director. Ms. Beal is the Chair of the Audit
Committee, replacing Iain McLaren who, in line with previous announcements,
did not seek re-election at the Company's Annual General Meeting and formally
stepped down on 13 June 2024. Ms. Beal is a member the Governance and
Nomination Committee and the Remuneration Committee.
Effective 12 June 2024, Joanne Williams and David Neuhauser joined the CEO and
CFO on the Disclosure Committee.
On 3 July 2024, the Company announced that Bert-Jaap Dijkstra, Executive
Director and Chief Financial Officer ("CFO"), has decided to leave the
Company. Mr. Dijkstra will remain in his post during the publication of the
Company's 2024 Half-Year Results and support the October 2024 redetermination
of the Company's reserve-based lending facility.
The Company is currently making good progress on both appointing a replacement
CFO and the ongoing search for a Chief Operating Officer.
(1) With an exception of Lemang, which will have an LDAR exercise implemented
within 12 months of starting operations.
Producing assets
Australia
Montara Project (100% working interest, operator)
The Montara fields averaged 4,951 bbls/d in H1 2024, compared to 2,931 bbls/d
in H1 2023. The year-on-year increase is primarily explained by Montara
production being shut in during the start of 2023 until late March 2023 for
repairs and maintenance activity on the Montara Venture FPSO's storage tanks.
Production during the first half of 2024 was impacted by the cyclone season
early in the year, and the temporary shut in of the H6 and Swift-2 wells
pending repairs. Both wells were brought back online early in the second half
of 2024.
The Montara Venture FPSO tank inspection and repair programme is progressing
well, resulting in increased oil storage capacity. This has allowed for the
shuttle tanker operation, which had been in place to provide operational
flexibility for Montara during the repair programme, to cease in late August
2024, earlier than planned.
The Group is progressing its plans to re-drill the Skua-11 well. This well is
expected to boost Montara production through reinstating production from the
Skua-11 well and is also targeting additional reserves in the Skua structure.
In total, three cargoes totalling c.0.8 mmbbls (H1 2023: one cargo of c.0.3
mmbbls) were lifted from Montara in the first half of 2024, with an average
oil price realisation of US$88.35/bbl, excluding the effect of hedging
(consisting of an average Brent price of US$83.82/bbl and average premium of
US$4.53/bbl). This compares to an average realisation of US$76.05/bbl in H1
2023 (Brent US$74.69/bbl and premium US$1.36/bbl). A further lifting of c.0.2
mmbbls was completed in early July 2024.
CWLH (33.33% working interest)
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
("CWLH") offshore western Australia, doubling its working interest to 33.33%.
During the first half of 2024, Jadestone's net production from the CWLH fields
averaged 2,951 bbls/d, compared to 1,569 bbls/d in H1 2023. The year-on-year
change is primarily explained by the increase in the Group's working interest
referenced above.
Following engagement with the CWLH joint venture, total abandonment trust fund
payments associated with the acquisition of the additional 16.67% interest
completed in early 2024 have been revised down to US$83.8 million. The Group
contributed US$65.0 million to the CWLH Abandonment Trust Fund during H1 2024
in connection with the CWLH acquisition, with the final trust fund payment of
US$18.8 million expected to be paid at the end of 2024.
The Group lifted one cargo of c.0.7 mmbbls in the first half for an average
oil price realisation of US$86.39/bbl, excluding the effect of hedging (H1
2023: no liftings net to the Jadestone) based on a Brent price of US$85.49/bbl
with a premium of US$0.90/bbl. Due to the acquisition of an additional 16.67%
share in CWLH and the ongoing good performance of the CWLH fields, a further
cargo of c.0.7 mmbbls was lifted in August 2024.
Stag (100% working interest, operator)
The Stag field averaged 1,921 bbls/d in the first half of 2024, compared to
2,879 bbls/d in H1 2023. The first half of 2023 benefited from the onset of
production of the Stag-50H and 51H wells drilled in late 2022. Stag field
production in H1 2024 reflected greater than normal weather-related downtime
in Q1 2024, a planned maintenance shutdown and mechanical issues in several
wells which required workovers.
The Group continues to review options for further infill wells on the Stag
field.
The Group sold one c.0.2 mmbbls cargo (H1 2023: two cargoes totalling c.0.5
mmbbls) of Stag crude in the first half of 2024. Premiums for Stag crude have
remained robust, with the H1 2024 cargo being sold at US$101.37/bbl, based on
average oil price realisation of US$85.49/bbl, excluding the effect of
hedging, plus a premium of US$15.88/bbl. A further cargo of Stag crude was
sold after the period end for a premium of US$10.69/bbl.
Malaysia
PM323 PSC (60% working interest, operator)
The PM323 PSC produced an average of 3,839 bbls/d net to Jadestone's working
interest in H1 2024 (H1 2023: 1,667 bbls/d). The year-on-year increase is a
result of the positive impact of the Group's infill drilling programme on the
East Belumut field in late-2023.
The Group is progressing plans for further infill drilling on the East Belumut
field, in particular focusing on the undrained southwestern area of the field
discovered during the 2023 campaign.
A total of c.0.4 mmbbls (H1 2023: 0.1mmbbls) were lifted from the PM323 PSC in
the first half of 2024, with an average oil price realisation of US$86.75/bbl
(H1 2023: US$83.31/bbl) based on a Brent price of US$82.62/bbl (H1 2023:
US$79.93/bbl) and a premium of US$4.14/bbl (H1 2023: US$3.38/bbl).
PM329 PSC (70% working interest, operator)
The PM329 PSC produced an average of 1,616 boe/d net to Jadestone's working
interest in H1 2024, consisting of 1,103 bbls/d of oil and 3.1 mmscf/d of gas
(H1 2023: 2,212 boe/d, consisting of 1,518 bbls/d of oil and 4.2 mmscf/d of
gas). The year-on-year decrease is primarily explained by natural decline.
A total of c.0.1 mmbbls (H1 2023: 0.2mmbbls) of oil were lifted from the PM323
PSC in the first half of 2024, with an average oil price realisation of
US$86.76/bbl (H1 2023: US$83.31/bbl), based on a Brent price of US$82.62/bbl
(2023: US$79.93/bbl) and a premium of US$4.14/bbl (2023: US$3.38/bbl). In
addition, c.0.6 bcf of gas was sold at an average realisation of US$1.64/mscf.
SFA Cluster (100% working interest, operator)
In July 2024, Jadestone was awarded a 100% participating interest in a Small
Field Asset Production Sharing Contract (the "SFA Cluster PSC") offshore
Peninsular Malaysia. The SFA 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. The SFA Cluster
PSC contains the Penara, Puteri-Padang and North Lukut fields, assets in which
Jadestone initially acquired a non-operated interest at the time of the
Group's entry into Malaysia in August 2021.
Jadestone currently estimates that the SFA Cluster PSC contains c.15 mmbbls of
gross 2C contingent resources. Leveraging the experience gained through the
successful 2023 infill drilling campaign on the PM323 licence, Jadestone
believes there is the potential for significant upside from future infill
drilling across the existing SFA Cluster fields, as well as opportunities on
the surrounding PM428 PSC. The Group intends to continue its technical
assessment of the SFA Cluster prior to submission of 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 SFA Cluster PSC (referenced above). The PM428
PSC carries a US$0.5 million financial commitment to reprocess existing
seismic and contains a number of prospects which, in a success case, could be
developed through existing infrastructure currently operated by Jadestone.
Indonesia
Akatara gas development (100% working interest 1 , operator)
The Akatara gas development is located within the Lemang Production Sharing
Contract onshore Sumatra in Indonesia. Akatara was previously developed as an
oil field, prior to being redeveloped by Jadestone to commercialise gas,
condensate and LPGs reserves in shallower zones.
Development activity at Akatara peaked in the first half of 2024. The focus
during the period was on completing the installation of equipment and
infrastructure at Akatara Gas Processing Facility ("AGPF"), tying in the
development wells, facilities and flowline, followed by pre-commissioning,
commissioning and start-up activities.
The workover campaign on the five existing Akatara wells, which provide gas to
the AGPF, was successfully completed during the period, with the five wells
flowing at an aggregate rate of 54 mmscf/d, significantly in excess of the
c.25 mmscf/d of raw feed gas required under the gas sales agreement. In
addition, the 8" diameter 17km pipeline exporting gas from the AGPF was
successfully tested and tied into the regional gas trunkline.
A major milestone was reached on 22 June 2024 with declaration of Mechanical
Completion at the AGPF 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 into the second half of 2024, with
commercial gas sales commencing on 31 July at a rate of c.4 mmscf/d, along
with LPG production. During August, commercial gas sales reached c.14 mmscf/d,
with production recently curtailed due to mechanical issues with the
facility's refrigeration compressors, where repairs are currently underway.
Thailand
Sinphuhorm (9.52% working interest, non-operated)
During the first half of 2024, the Sinphuhorm field produced an average of
1,585 boe/d (1,565 boe/d gas and 23 bbls/d of condensate). Production for the
period 23 February 2023 (when Jadestone completed the acquisition of its
Sinphuhorm interest) to 30 June 2023 averaged 1,531 boe/d, or 1,083 boe/d
averaged over the first half of 2023.
Activity at the field during the first half of 2024 mainly comprised a booster
compression project, which aims to sustain plateau production levels over the
remaining life of the concession. The booster compression project was
completed at the end of May 2024.
As this is an investment in associate, the Group does not recognise its share
of revenues and production costs, instead recognising its share of results of
associate. Dividends of US$3.8 million were received in H1 2024 (H1 2023: no
dividends received). A further dividend of US$0.8 million was distributed
early July 2024 after the period end.
Pre-production assets
Vietnam
Block 51 (100% working interest, operator) and Block 46/07 (100% working
interest, operator) PSCs
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 water offshore southwest Vietnam.
Following signature of the HoA, the Group commenced detailed negotiations over
a fully termed GSPA, which are currently ongoing. The GSPA is also a precursor
to the submission of an updated Field Development Plan for the Nam Du and U
Minh fields, the approval of which is required before a Final Investment
Decision can be taken. The Group is currently updating this FDP, which will
specify 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 exploration well. This
commitment has been extended several times from 2015 up to the end of June
2024. Historically, extension requests have been approved after expiry. An
extension request was filed by the Company in February 2024 and is consistent
with previous successful extensions, in that Jadestone proposes to drill this
well as part of the development drilling for the Nam Du field development
project.
The Tho Chu discovery in Block 51 was under a suspended development area
status. The Group is working with Petrovietnam and other government entities
to obtain a suspension of the relinquishment obligation for Block 51.
FINANCIAL REVIEW
The following table provides selected financial information of the Group,
which was derived from, and should be read in conjunction with, the unaudited
condensed consolidated interim financial statements for the period ended 30
June 2024.
USD'000 except where indicated Six months ended 30 June 2024 Six months ended 30 June 2023 Twelve months ended 31 December 2023
Production, boe/day(1) 16,867 12,339 13,813
Sales volume, barrels of oil equivalent (boe) 2,330,574 1,119,011 3,862,741
Realised oil price per barrel of oil equivalent 88.73 86.15 87.34
(US$/boe)(2)
Gas sales, thousand standard cubic feet (mscf) 559,888 752,660 1,366,505
Realised gas price per thousand standard cubic feet 1.64 1.41 1.53
(US$/mscf)
Revenue(3) 185,060 86,660 309,200
Production costs (136,324) (90,650) (232,772)
Adjusted unit operating costs per barrel of oil 31.72 40.27 37.24
equivalent (US$/boe)(4)
Adjusted EBITDAX(4) 60,215 (3,127) 90,647
Unit depletion, depreciation & amortisation 13.02 13.15 14.14
(US$/boe)
Impairment of assets - - (29,681)
Loss before tax (29,129) (70,275) (102,766)
Loss after tax (31,119) (59,934) (91,274)
Loss per ordinary share: basic and diluted (0.06) (0.13) (0.18)
(US$)
Operating cash flows before movement in working 27,946 (24,179) 36,499
capital
Capital expenditure 47,618 23,807 115,882
Net (debt)/cash(4) (69,131) 7,782 (3,596)
Benchmark commodity price and realised price
l The average oil price realisation, excluding the effect of hedging increased
in H1 2024 by 3.0% to US$88.73/bbl, compared to US$86.15/bbl in H1 2023. The
higher realised price was due benchmark Brent price increasing 8.9% to
$84.14/bbl from $77.28/bbl in H1 2023. However, this gain was impacted by a
reduction in average realised premium, which reduced to $4.59/bbl in H1 2024
from $8.87/bbl in H1 2023. This decrease was caused by the composition of
liftings: Stag, with the highest premium, had lower lifting volumes, while
CWLH, with a lower premium, had higher volumes lifted during the period.
(1) Production includes the Sinphuhorm Asset gas production in accordance with
Petroleum Resource Management Systems guidelines, non-IFRS measures. However,
in accordance with IAS 28 the investment is accounted for as an associated
undertaking and only recognises dividends received. Accordingly, the revenue
and production costs from the Sinphuhorm Assets are excluded from the Group's
financial results. Sinphuhorm production is included in the Group's production
figures.
(2) Realised oil price represents the actual selling price inclusive of
premiums, excluding the effect from hedging.
(3) Revenue in H1 2024 and YE 2023 includes a hedging charge of US$15.4
million and US$10.3 million respectively from the commodity swap contracts
entered into in support of the RBL facility.
(4) Adjusted unit operating cost per boe, adjusted EBITDAX and net (debt)/cash
are non-IFRS measures and are explained in further detail on the Non-IFRS
Measures section in this document.
Production and liftings
The average production recorded a 37% growth for H1 2024 with 16,867 boe/d
compared to 12,339 boe/d in H1 2023. The overall increase of 4,528 boe/d was
the result of the following factors:
· Montara's production rose by 2,020 bbl/d, reflecting the phased
restart that began in March 2023, which impacted H1 2023 output. In contrast,
H1 2024 benefited from a full six months of production.
· PenMal added 1,576 bbl/d following the successful PM323 infill
drilling in late 2023, partially offset with natural field decrease at
PM329.
· CWLH's production increased by 1,382 bbl/d following the
completion of a second acquisition in February 2024, which doubled the working
interest in the assets.
· Sinphuhorm contributed an additional 508 boe/d in H1 2024,
benefiting from a full six months of production compared to H1 2023, when the
asset was acquired in February 2023; and
The above increase was partly offset by:
· Stag decreased 958 bbls/d due to extended downtime caused by
adverse weather conditions and increased workover activity due to mechanical
issues in several wells which required workovers.
Lifted oil volumes were higher in H1 2024 compared to H1 2023 predominately
due to:-
Six months ended 30 June 2024 Six months ended 30 June 2023
In mmbbls except where indicated
Remark
One lifting immediately following the completion of second acquisition.
CWLH 0.7 -
H1 2024 3 liftings vs H1 2023 1 lifting with phased production resumed in late
March 2023.
Montara 0.8 0.3
One lifting in H1 2024 compared to two liftings in H1 2023.
Stag 0.2 0.5
Successful drilling campaign led to higher production available for lifting
nomination.
PenMal 0.5 0.3
Total 2.2 1.1 H1 2024 10 liftings vs H1 2023 6 liftings.
PenMal gas sales Decrease in gas sales driven by natural decline at PM329 asset.
(mmscf) 559.9 752.7
Revenue
The Group generated gross revenues before hedging results of US$200.5 million
a 131% increase over the comparable period (H1 2023: US$86.7 million).
A commodity swap hedge resulted in a charge of US$15.4 million (H1 2023: nil),
resulting in net revenue of US$185.1 million in H1 2024 (H1 2023: US$86.7
million).
The period-on-period increase in total net revenues of US$98.4 million is due
to:
· Higher lifted volumes, which resulted in an increase of US$111.4
million in H1 2024; inclusive of US$45.8 million from CWLH lifting of 530,484
bbls.
· Increased average oil price realisation, excluding the effect of
hedging of US$88.73/bbl in H1 2024 (compared to US$86.15/bbl in H1 2023),
adding US$2.6 million to revenue;
· Lower gas sales with reduced average gas price realisation of
US$1.64/mscf in H1 2024 (compared to US$1.41/mscf in H1 2023) resulted in a
decrease of US$0.2 million of revenue and;
· Hedging resulted in a loss of US$15.4 million in H1 2024, with no
impact in H1 2023, as the program commenced in H2 2023.
Production costs
Production costs in H1 2024 totalled US$136.3 million, a 50.3% increase from
US$90.7 million in H1 2023. This US$45.7 million increase was primarily driven
by changes in crude inventories and partner over/under lift imbalances. If
movements in crude inventory and partner over/under lift imbalances are
excluded there is a increase of $0.9 million, totaling $116.4 million compared
to $115.5 million in H1 2023, indicating relatively constant underlying core
operational expenses as detailed below:
H1 2024 H1 2023 Variance Note
USD'000 USD'000 USD'000
Operating costs 53,693 52,562 1,131 (i)
Workovers 10,633 9,531 1,102 (ii)
Logistics 13,956 14,743 (787) (iii)
Repairs and maintenance 28,090 28,378 (288) (iv)
Tariffs and transportation costs 3,656 3,035 621 (v)
Supplementary payments and royalties 6,324 7,298 ( (974) (vi)
Underlift, overlift and crude inventories
movement 19,972 (24,897) 44,869 (vii)
136,324 90,650 45,674
(i) Operating cost rose by US$1.1 million, or 2%, to
US$53.7 million in H1 2024 from US$52.6 million (H1 2023). This increase
between periods was mainly explained by:
- CWLH operating costs increased by US$6.5 million, reflecting
the acquisition of an additional 16.67% in February 2024, resulting in a total
working interest of 33.33% from that point compared to 16.67% for H1 2023.
- Stag shuttle tanker charter rates reduced by US$3.4
million compared to H1 2023.
- Montara's operating costs decreased by US$4.6 million, from
US$24.4 million in H1 2023 to US$19.8 million in H1 2024. This reduction was
primarily due to lower diesel consumption at the Montara in H1 2024 compared
to H1 2023 which required more diesel for FPSO and operation of compressor
during wells shut-in and production start-up in late March 2023.
- PenMal operating costs increase by US$2.6
million due to the rectification costs at Abu platform and additional
operational expenses associated with the non-operated assets.
(ii) Workover costs increased by US$1.1 million to US$10.6
million (H1 2023: US$9.5 million), with PenMal increasing US$0.7 million to
improve well integrity and performance and US$0.4 million at Stag to carried
out standard replacement for underperforming downhole pumps with 6 workovers
during H1 2024 compared five in H1 2023.
(iii) Logistics costs reduced by US$0.8 million to US$13.9
million (H1 2023: US$14.7 million), primarily due unavailability of helicopter
for use at Montara hence lower standing cost incurred during H1 2024 by US$1.1
million, and a US$0.3 million reduction at PenMal, with decreased offshore
activities at the Puteri cluster in H1 2024 compared to H1 2023.This decrease
was offset by a US$0.6 million increase at Stag, caused by multiple cyclone
events that necessitated more frequent use of support vessels and helicopter
services compared to the same period year-ago.
(iv) Repair and maintenance ("R&M") reduced US$0.3
million to US$28.1 million (H1 2023: US$ 28.4 million) due to a net increase
at Stag of US$1.7 million for one-off remedial activities carried out on its
calm buoy and an export pipeline inspection offset by a decrease of US$2.0
million due to reduced activities at PenMal SFA cluster compared to the same
period year-ago.
(v) Tariffs and transportation increased by US$0.7 million
to US$ 3.7 million (H1 2023: US$3.0 million) predominately due to three cargo
liftings from Montara in H1 2024 compared to one in H1 2023.
(vi) Supplementary payment and royalties decreased US$1.0
million mainly reflecting the net movement from PenMal of US$2.5 million
mainly due to lower realised prices compared to H1 2023. These supplementary
payments are based on the differential between the realised price and the
escalated PSC base price. This decrease was partially offset by an US$1.5
million increase in CWLH levies due to acquisition of the additional 16.67%
ownership interest.
(vii) Underlift, overlift, and crude inventory movements
increased by US$44.9 million, primarily due to the purchase price accounting
for the second acquisition of CWLH. The acquisition of the second tranche of
CWLH increased production costs by US$45.8 million, attributable to the
530,484 bbls of underlift acquired. This underlift was sold in March 2024, and
the cost associated with acquiring the crude inventory is recorded under crude
inventories and partner over/under lift imbalances. As per IFRS 3 Business
Combinations, all identifiable assets acquired in an acquisition must be
valued at their fair value. In this case, the crude inventory was valued at
the price achieved during the April lifting, which was US$86.28 per barrel
(refer to Note 8, Acquisition of Interest in CWLH Joint Operation).
Adjusted unit operating cost per boe was US$31.72/bbl (H1 2023: US$40.27/bbl)
(see Non-IFRS Measures section below in this document). The decrease is
predominately due to increased production and a stable production cost.
Depletion, depreciation and amortisation ("DD&A")
Depletion charges for oil and gas properties increased by 73.4% to US$30.0
million in H1 2024, compared to US$17.3 million in H1 2023. This increase was
primarily due to a 37% rise in production during H1 2024, higher unit rates
driven by an increase in Asset Retirement Obligations (ARO), and the
commencement of production from the PM323 infill wells. The depletion cost on
a unit basis in H1 2024 was US$13.02/boe, a decrease of 1.0% compared to
US$13.15/boe in H1 2023.
Depreciation of the Group's right-of-use assets and plant and equipment
increased to US$8.2 million in H1 2024 from US$7.3 million in H1 2023, mainly
due to lease changes and renewals.
Other expenses
Other expenses increased US$5.9 million during H1 2024 to US$14.3 million (H1
2023: US$8.4 million) predominately related to the recognition of a provision
for two Lemang contingent payments with a combined fair value of US$5.5
million associated with the average brent price and average Saudi CP(1)
exceeding US$80/bbl and USD620/MT respectively in first year of production.
These two events were not recognised H1 2023 as at the time, future prices
were not anticipated to exceed these forecasted prices (full details of the
contingent payments were detailed in the Annual Report Note 37 Provisions).
Finance costs
Finance costs in H1 2024 were US$19.5 million (H1 2023: US$22.5 million), a
decrease of US$3.0 million, predominately due to:
· A warrant reserve was established during the 2023 equity raise,
resulting in a US$6.1 million charge in that period. No corresponding charge
was recorded in H1 2024.
· Lending fees decreased US$1.8 million to US$0.4 million in H1
2024, from US$2.2 million in H1 2023. This decrease primarily resulted from
one-off, non-recurring fees associated with the equity raise and working
capital facility in the previous period.
(1)The term "Saudi CP" typically refers to the Saudi Contract Price (CP),
which is a benchmark price for liquefied petroleum gas (LPG) in the global
market.
· The RBL accretion fees and interest expenses increased by US$3.0
million to US$5.5 million in H1 2024, up from US$2.5 million in H1 2023. This
increase reflects higher borrowings and a full six months of expenses in H1
2024, compared to the partial period of expense incurred in H1 2023, after
entering into the RBL in May 2023.
· ARO accretion expense increased by US$0.9 million to US$10.5
million in H1 2024, up from US$9.6 million in H1 2023. This increase in Asset
Retirement Obligation (ARO) was primarily driven by two factors: the
acquisition of additional CWLH ownership share in February 2024, and the
increased percentage of completion for Lemang's EPCI project.
Other financial gains
Other financial gains in H1 2024 amounted to US$1.0 million (H1 2023: US$
nil), resulting from the revaluation of the warrant liability created during
the 2023 equity raise. The warrant liability, recorded under Current
Liabilities, is revalued at each reporting date. This gain reflects a
reduction in the liability from US$3.5 million at year-end 2023 to US$2.5
million in H1 2024.
Taxation
The tax expense of US$2.0 million in H1 2024 (H1 2023: tax credit of US$10.3
million) comprised current tax charge of US$7.5 million (H1 2023: tax credit
US$2.1 million) and a deferred tax credit of US$5.5 million (H1 2023: tax
credit of US$8.2 million).
The tax charge on the Group's loss differs from the amount that would arise
using the standard rate of income tax applicable in the countries of operation
as explained below:
H1 2024 H1 2023
USD'000 USD'000
Loss before tax (29,129) (70,275)
Tax calculated at the domestic rates appliable to the profit/loss in the
respective countries (Australia 30%, Malaysia 38% and 24% and Singapore 17%)
(4,646) (18,100)
Less the effects of:
Australian Petroleum Resource Rent Tax (PRRT) credit (5,741) (231) (
Deferred PRRT tax expense 545 -
Non-deductible expenses 1,787 5,191
Deferred tax assets not recognised 7,856 4,977
Other income not subjected to tax (482) -
Adjustments to prior year 2,671 (2,178)
Tax expense/(credit) for the period 1,990 (10,341)
RECONCILIATION OF CASH
H1 2024 H1 2023
US$'000 Reclassified(1)
Cash and cash equivalent at the beginning of 153,404 123,329
period
Revenue 185,060 86,660
Other operating income(2) 3,525 3,324
Production costs (136,324) (90,650)
Administrative staff costs(2) (15,541) (15,080)
General and administrative expenses(2) (8,774) (8,433)
Operating cash flows before movements in 27,946 (24,179)
working capital
Movements in working capital(1) (40,271) (71,377)
Net tax paid (16,486) (4,755)
Purchases of intangible exploration assets, oil and (27,151) (23,439)
gas properties, and plant and equipment(3)
Cash paid for acquisition of Sinphuhorm Assets - (27,853)
Cash received for acquisition of additional interest 5,236 -
16.67% of CWLH Assets
Dividends received from associate 3,768 -
Interest received 410 1,466
Net proceeds from issuance of shares - 51,070
Shares repurchased - (2,084)
Repayment of lease liabilities (7,658) (7,009)
Total drawdown from borrowings 43,000 161,000
Repayment of borrowings - (50,000)
Repayment of costs and interest of borrowings (8,394) (793)
Other financing activities (2,935) (6,594)
Total cash and cash equivalent at the end of 130,869 118,782
period
NON-IFRS MEASURES
The Group uses certain performance measures that are not specifically defined
under IFRS, or other generally accepted accounting principles. These
non-IFRS measures comprise adjusted unit operating cost per barrel of oil
equivalent (adjusted opex/boe), adjusted EBITDAX, outstanding debt, and net
cash.
The following notes describe why the Group has selected these non-IFRS
measures.
(1) Certain H1 2023 comparative information has been reclassified. The
placement of decommissioning trust fund for the CWLH Assets are now
reclassified from investing activities to working capital in accordance with
the nature of activities.
(2) Other operating income, administrative staff costs and general and
administrative expenses adjusted figures are non-IFRS measures.
(3) Total capital expenditure was US$47.6 million (H1 2023: US$23.8 million),
comprising total capital expenditure paid of US$27.1 million (H1 2023: US$23.4
million), accrued capital expenditure of US$16.2 million (H1 2022: US$0.4
million) and capitalisation of borrowing costs of US$4.3 million (H1 2023:
nil).
Adjusted unit operating costs per barrel of oil equivalent (Adjusted opex/boe)
Adjusted opex/boe is a non-IFRS measure used to monitor the Group's operating
cost efficiency, as it measures operating costs to extract hydrocarbons from
the Group's producing reservoirs on a unit basis.
Adjusted opex/boe is defined as total production costs excluding oil
inventories movement and underlift/overlift, write down of inventories,
workovers (to facilitate better comparability period to period) and
non-recurring repair and maintenance. It includes lease payments related to
operational activities, net of any income earned from leasing of right-of-use
assets involved in production, and excludes transportation costs, PenMal Asset
supplementary payments, costs associated with the PenMal non-operating assets
and DD&A.
The adjusted production costs are then divided by total produced barrels of
oil equivalent for the prevailing period to determine the unit operating cost
per barrel of oil equivalent.
Twelve months ended
Six months ended 30 June 2024 Six months ended 30 June 31 December 2023
2023
USD'000 except where indicated
Production costs (reported) 136,324 90,650 232,772
Adjustments
Lease payments related to operating activities(1) 8,764 7,493 16,155
Underlift, overlift and crude inventories (19,972) 24,897 9,297
movement(2)
Workover costs(3) (10,633) (9,531) (17,562)
Other income(4) (3,200) (2,584) (6,375)
Non-recurring operational costs(5) (6,775) (11,565) (19,654)
Non-recurring repair and maintenance(6) (5,343) (312) (1,773)
Transportation costs(7) (3,656) (3,035) (7,502)
PenMal Assets supplementary payments and (6,324) (7,298) (16,056)
Australian royalties(8)
PenMal PNLP assets operational costs(9) (994) (6,670) (19,273)
Adjusted production costs 88,191 82,045 170,029
Total production (barrels of oil equivalent) 2,780,677 2,037,420 4,566,060
Adjusted unit operating costs per barrel of oil 31.72 40.27 37.24
equivalent
(1) Lease payments related to operating activities are lease payments
considered to be operating costs in nature, including leased helicopters for
transporting offshore crews. These lease payments are added back to reflect
the true cost of production.
(2) Underlift, overlift and crude inventories movement are added back to the
calculation to match the full cost of production with the associated
production volumes (i.e., numerator to match denominator).
(3) Workover costs are excluded to enhance comparability. The frequency of
workovers can vary significantly, across periods.
(4) Other income represents the rental income from a helicopter rental
contract (a right-of-use asset) to a third party.
(5) Non-recurring operational costs in H1 2024 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 FPSO.
(6) Non-recurring repair and maintenance costs in H1 2024 predominately
related to floating hose repair at Montara, CALM buoy coating remediation and
maintenance pigging of export flowline at Stag, and rectification costs of the
cranes and platforms of PNLP asset at PenMal. The costs during H1 2023
predominately related to the repair of a gas turbine generator at the PenMal
Assets PM329 PSC.
(7) Transportation costs includes the pipeline tariff at PenMal 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 include a temporary levy passed
by the Australian Government on offshore petroleum production and a levy on
the wellhead value of primary production licence from the CWLH Assets.
(9) Similar to H1 2023, PenMal non-operated assets operational costs in H1
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 don't contribute to production.
Adjusted EBITDAX
Adjusted EBITDAX is a non-IFRS measure which does not have a standardised
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 follows:
Twelve months ended
Six months ended 30 June 2024 Six months ended 30 June 2023 31 December 2023
USD'000
Revenue 185,060 86,660 309,200
Production costs (136,324) (90,650) (232,772)
Administrative staff costs (15,757) (15,538) (30,197)
Other expenses (14,312) (8,446) (22,841)
Share of results of associate 2,124 - 2,640
Other income, excluding interest income 3,528 3,324 14,404
Other financial gains 1,001 - -
Unadjusted EBITDAX 25,320 (24,650) 40,434
Non-recurring
Net loss from oil price and foreign exchange 15,425 - 10,395
derivatives
Non-recurring opex(1) 13,112 18,547 40,700
Assets written off 38 - 3,067
Change in provision - Lemang PSC contingent 5,500 - (7,653)
payments
Others(2) 820 2,976 3,704
34,895 21,523 50,213
Adjusted EBITDAX 60,215 (3,127) 90,647
(1) Non-recurring opex mainly 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 one-off repair and maintenance
costs predominately related to CALM buoy coating remediation and maintenance
pigging of export flowline at Stag, and rectification costs of the cranes and
platforms of AAKBNLP asset at PenMal. The H1 2023 non-recurring costs 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.
(2) Includes business development related expenses, external funding sourcing
costs, internal reorganisation costs and fair value loss on contingent
consideration.
Net (debt)/cash
Net (debt)/cash is a non-IFRS measure which does not have a standardised
definition prescribed by IFRS. Management uses this measure to analyse the
net borrowing position of the Group.
30 June 30 June 31 December 2023
USD'000 2024 2023
Borrowings (principal sum) (200,000) (111,000) (157,000)
Cash and cash equivalents 130,869 118,782 153,404
Net (debt)/cash (69,131) 7,782 (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.
2024 PRINCIPAL FINANCIAL RISKS AND UNCERTAINTIES
The Group manages principal risks and uncertainties via its risk management
framework. The Group is exposed to a variety of political, technological,
environmental, operational and financial risks which are monitored and/or
mitigated to acceptable levels.
The Group's risk management framework provides a systematic process for the
identification of the principal risks which have the possibility of impacting
the Group's strategic objectives. The Board regularly reviews the principal
risks and defines corporate targets based on acceptable levels of risk. The
Board assesses material risks with a full review of the risk matrix at least
twice per year.
Details of the principal risks and uncertainties faced by the Group as at 30
June 2024 remain unchanged from the risks disclosed in the 2023 Annual Report
pages 31 to 34. The Group's risk mitigation activities also remain
unchanged.
GOING CONCERN
The Directors have adopted the going concern basis in preparing these
unaudited condensed consolidated interim financial statements, having
considered the principal financial risks and uncertainties of the Group.
The Directors believe that the Group is well placed to manage its financing
and other business risks satisfactorily. The Directors have a reasonable
expectation that the Group will have adequate resources to continue in
operation for at least 18 months from the balance sheet date of these
unaudited condensed consolidated interim financial statements. They
therefore consider it appropriate to adopt the going concern basis of
accounting in preparing these financial statements. Details of going concern
are disclosed in Note 2.
STATEMENT OF DIRECTORS' RESPONSIBILITIES
The Directors confirm that to the best of their knowledge:
a. the condensed consolidated interim set of financial statements has been
prepared in accordance with IAS 34 Interim Financial Reporting;
b. the interim management report includes a fair review of the information
required by DTR 4.2.7R (indication of important events during the first six
months and description of principal risks and uncertainties for the remaining
six months of the year); and
c. the interim management report includes a true and fair review of the
information required by DTR 4.2.8R (disclosure of related parties'
transactions and changes therein).
By order of the Board,
Bert-Jaap Dijkstra
Executive
Director
Chief Financial
Officer
17 September
2024
CAUTIONARY STATEMENT
This Interim Management Report (IMR) has been prepared solely to provide
additional information to shareholders to assess the Group's strategies and
the potential for those strategies to succeed. The IMR should not be relied
on by any other party or for any other purpose.
The IMR contains certain forward-looking statements. These statements are made
by the directors in good faith based on the information available to them up
to the time of their approval of this report but such statements should be
treated with caution due to the inherent uncertainties, including both
economic and business risk factors, underlying any such forward-looking
information.
Condensed Consolidated Statement of Profit or Loss and Other Comprehensive
Income
for the six months ended 30 June 2024
Six months Six months Twelve months ended 31 December 2023
ended ended
30 June 30 June
2024 2023
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
Consolidated statement of profit or loss
Revenue 185,060 86,660 309,200
Production costs 4 (136,324) (90,650) (232,772)
Depletion, depreciation and amortisation 4 (38,180) (24,574) (76,141)
Administrative staff costs (15,757) (15,538) (30,197)
Other expenses 4 (14,312) (8,446) (22,841)
Impairment of oil and gas properties - - (29,681)
Share of results of associate 11 2,124 - 2,640
Other income 6,779 4,790 18,855
Finance costs 5 (19,520) (22,517) (41,829)
Other financial gains 1,001 - -
Loss before tax (29,129) (70,275) (102,766)
Income tax (expense)/credit 6 (1,990) 10,341 11,492
Loss for the period/year (31,119) (59,934) (91,274)
Loss per ordinary share
Basic and diluted (US$) 7 (0.06) (0.13) (0.18)
Other comprehensive loss
Loss for the period/year (31,119) (59,934) (91,274)
Items that may be reclassified subsequently
to profit or loss:
Loss on unrealised cash flow hedges (34,440) (10,985) (30,509)
Hedging loss reclassified to profit or loss 15,425 - 10,322
(19,015) (10,985) (20,187)
Tax credit relating to components of other 5,704 2,160 6,056
comprehensive loss
Other comprehensive loss (13,311) (8,825) (14,131)
Total comprehensive loss for the (44,430) (68,759) (105,405)
period/year
Condensed Consolidated Statement of Financial Position as at 30 June 2024
30 June 30 June 31 December 2023
2024 2023
Unaudited Unaudited Audited
Restated*
Notes USD'000 USD'000 USD'000
Assets
Non-current assets
Intangible exploration assets 9 80,440 78,730 79,564
Oil and gas properties 10 480,189 429,548 457,202
Plant and equipment 10 10,508 7,329 10,462
Right-of-use assets 10 22,462 37,980 31,099
Investment in associate 11 25,007 27,853 26,651
Other receivables and prepayment 12 262,493 191,127 141,860
Deferred tax assets 45,678 16,688 26,774
Cash and cash equivalents 13 1,356 1,000 1,008
Total non-current assets 928,133 790,255 774,620
Current assets
Inventories 56,243 47,818 33,654
Trade and other receivables 12 33,354 72,716 124,379
Tax recoverable 4,801 8,496 4,085
Cash and cash equivalents 13 129,513 117,782 152,396
Total current assets 223,911 246,812 314,514
Total assets 1,152,044 1,037,067 1,089,134
Equity and liabilities
Equity
Capital and reserves
Share capital 14 456 456 456
Share premium account 14 51,827 51,827 51,827
Merger reserve 15 146,270 146,270 146,270
Share based payments reserve 27,889 27,365 27,673
Capital redemption reserve 16 24 24 24
Hedging reserve 17 (27,442) (8,825) (14,131)
Accumulated losses (189,468) (127,009) (158,349)
Total equity 9,556 90,108 53,770
*Certain H1 2023 comparative information has been restated. Please refer to
Note 26.
30 June 30 June 31 December 2023
2024 2023
Unaudited Unaudited Audited
Restated*
Notes USD'000 USD'000 USD'000
Non-current liabilities
Provisions 18 682,915 581,625 503,170
Borrowings 19 169,135 82,194 147,313
Lease liabilities 10,353 24,818 18,746
Other payable 20 17,337 29,014 16,966
Derivative financial instruments 21 5,897 6,386 6,708
Deferred tax liabilities 71,556 73,628 65,829
Total non-current liabilities 957,193 797,665 758,732
Current liabilities
Borrowings 19 29,829 22,802 7,260
Lease liabilities 14,192 14,107 14,118
Trade and other payables 20 88,381 73,752 113,979
Derivative financial instruments 21 35,762 4,599 17,977
Warrants liability 22 2,541 6,147 3,469
Provisions 18 11,994 16,941 108,525
Tax liabilities 2,596 10,946 11,304
Total current liabilities 185,295 149,294 276,632
Total liabilities 1,142,488 946,959 1,035,364
Total equity and liabilities 1,152,044 1,037,067 1,089,134
*Certain H1 2023 comparative information has been restated. Please refer to
Note 26.
Condensed Consolidated Statement of Changes in Equity
for the six months ended 30 June 2024
Share-
Share based Capital
Share premium Merger payments redemption Hedging Accumulated
capital account reserve reserve reserve reserve losses Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
As at 1 January 2023 (Restated)* 339 983 146,270 26,907 21 - (64,991) 109,529
Loss for the period - - - - - - (59,934) (59,934)
Other comprehensive loss for the - - - - - (8,825) - (8,825)
period
Loss for the period, representing - - - - - (8,825) (59,934) (68,759)
total comprehensive loss for
the period
Share-based payments - - - 458 - - - 458
Shares issued (Note 14) 120 52,846 - - - - - 52,966
Transaction costs associated with - (2,002) - - - - - (2,002)
issuance of shares (Note 14)
Shares repurchased (Note 14) (3) - - - 3 - (2,084) (2,084)
Total transactions with owners, 117 50,844 - 458 3 - (2,084) 49,338
recognised directly in equity
As at 30 June 2023 (Restated)* 456 51,827 146,270 27,365 24 (8,825) (127,009) 90,108
*Certain H1 2023 comparative information has been restated. Please refer to
Note 26.
Share-
Share based Capital
Share premium Merger payments redemption Hedging Accumulated
capital account reserve reserve reserve reserve losses Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
As at 1 January 2023 (*Restated) 339 983 146,270 26,907 21 - (64,991) 109,529
Loss for the year - - - - - - (91,274) (91,274)
Other comprehensive loss for the - - - - - (14,131) - (14,131)
year
Loss for the year, representing - - - - - (14,131) (91,274) (105,405)
total comprehensive loss for
the year
Share-based payments - - - 766 - - - 766
Shares issued (Note 14) 120 52,846 - - - - - 52,966
Transaction costs associated with - (2,002) - - - - - (2,002)
issuance of shares (Note 14)
Shares repurchased (Note 14) (3) - - - 3 - (2,084) (2,084)
Total transactions with owners, 117 50,844 - 766 3 - (2,084) 49,646
recognised directly in equity
As at 31 December 2023 456 51,827 146,270 27,673 24 (14,131) (158,349) 53,770
*Certain H1 2023 comparative information has been restated. Please refer to
Note 26.
Share-
Share based Capital
Share premium Merger payments redemption Hedging Accumulated
capital account reserve reserve reserve reserve losses Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
As at 1 January 2024 456 51,827 146,270 27,673 24 (14,131) (158,349) 53,770
Loss for the period - - - - - - (31,119) (31,119)
Other comprehensive loss for the - - - - - (13,311) - (13,311)
period
Loss for the period, representing - - - - - (13,311) (31,119) (44,430)
total comprehensive loss for
the period
Share-based payments - - - 216 - - - 216
Total transactions with owners, - - - 216 - - - 216
recognised directly in equity
As at 30 June 2024 456 51,827 146,270 27,889 24 (27,442) (189,468) 9,556
Condensed Consolidated Statement of Cash Flows for the six months ended 30
June 2024
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
Reclassified(*)
Notes USD'000 USD'000 USD'000
Operating activities
Loss before tax (29,129) (70,275) (102,766)
Adjustments for:
Depletion, depreciation and amortisation 4 / 10 38,180 24,574 76,141
Finance costs 5 19,520 22,517 41,829
Impairment of oil and gas properties - - 29,681
Assets written off 38 - 5,114
Share-based payments 216 458 766
Allowance for slow moving inventories - 13 655
Change/(reversal of) in provision 5,500 - (7,653)
Interest income (3,251) (1,466) (4,451)
Share of result of associate 11 (2,124) - (2,640)
Other financial gains (1,001) - -
Unrealised foreign exchange loss (3) - (177)
Operating cash flows before movements in 27,946 (24,179) 36,499
working capital
Increase in trade and other (27,286) (77,158) (80,900)
receivables
Decrease/(increase) in inventories 29,377 (18,630) (15,655)
(Decrease)/increase in trade and other (42,362) 24,411 62,392
payables
Cash (used in)/generated from operations (12,325) (95,556) 2,336
Net tax paid (16,486) (4,755) (14,461)
Net cash used in operating activities (28,811) (100,311) (12,125)
Investing activities
Cash paid for acquisition of Sinphuhorm 11 - (27,853) (27,853)
Assets
Cash received for acquisition of additional 8 5,236 - -
interest 16.67% of CWLH Assets
Payment for oil and gas properties 10 (26,362) (22,703) (107,500)
Payment for plant and equipment 10 (291) (302) (516)
Payment for intangible exploration assets 9 (498) (434) (1,508)
Dividend received from associate 11 3,768 - 3,842
Interest received 410 1,466 4,451
Net cash used in investing activities (17,737) (49,826) (129,084)
*Certain H1 2023 comparative information has been reclassified. Please refer
to Note 26.
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
Reclassified(*)
Notes USD'000 USD'000 USD'000
Financing activities
Net proceeds from issuance of shares - 51,070 50,964
Shares repurchased - (2,084) (2,084)
Total drawdown from borrowings 43,000 161,000 232,000
Repayment of borrowings - (50,000) (75,000)
Interest on borrowings paid (8,252) (793) (5,007)
Borrowing costs paid - (5,535) (7,595)
Commitment fees of borrowings paid (142) - (658)
Repayment of lease liabilities (7,658) (7,009) (14,400)
Interest on lease liabilities paid (1,319) (1,027) (2,771)
Other interest and fees paid (1,616) (32) (4,165)
Net cash generated from financing 24,013 145,590 171,284
activities
Net (decrease)/increase in cash and cash (22,535) (4,547) 30,075
equivalents
Cash and cash equivalents at beginning of the 153,404 123,329 123,329
period/year
Cash and cash equivalents at end of the 13 130,869 118,782 153,404
period/year
*Certain H1 2023 comparative information has been reclassified. Please refer
to Note 26.
Explanation Notes to the Condensed Consolidated Interim Financial Statements
for the six months ended 30 June 2024
1. GENERAL INFORMATION
Jadestone Energy plc (the "Company" or "Jadestone") is an oil and gas company
incorporated and registered in England and Wales. The Company's registration
number is 13152520. The Company is the ultimate parent company of all
Jadestone subsidiaries (the "Group").
The Company's shares are traded on AIM under the symbol "JSE".
The financial statements are expressed in United States Dollars ("US$" or
"USD").
The Group is engaged in production, development, exploration and appraisal
activities in Australia, Malaysia, Vietnam, Indonesia and Thailand. The
Group's producing assets are in the Vulcan (Montara) basin, Carnarvon (Stag)
basin and Cossack, Wanaea, Lambert, and Hermes (CWLH) 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 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. The registered office of the Company is 6th Floor, 60
Gracechurch Street, London, EC3V 0HR United Kingdom.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PREPARATION
The annual financial statements of the Jadestone Energy plc will be prepared
in accordance with United Kingdom adopted International Accounting Standards.
The condensed set of consolidated financial statements included in this
half‑yearly financial report has been prepared in accordance with United
Kingdom adopted International Accounting Standard 34 'Interim Financial
Reporting'.
These unaudited condensed consolidated interim financial statements do not
comprise statutory accounts within the meaning of section 435 of the Companies
Act 2006 ("the Act"). They do not contain all disclosures required by IFRS for
annual financial statements and should be read in conjunction with the Group's
audited consolidated financial statements for the year ended 31 December 2023.
The information for the year ended 31 December 2023 does not constitute
statutory accounts as defined in section 434 of the Companies Act 2006. A
copy of the statutory accounts for that year has been delivered to the
Registrar of Companies. The auditors reported on those accounts: their
report was unqualified, did not draw attention to any matters by way of
emphasis and did not contain a statement under section 498(2) or (3) of the
Companies Act 2006.
These financial statements have been prepared on an historical cost basis,
except for financial instruments classified as financial instruments at fair
value, which are stated at their fair values, and operating leases which are
stated at the present value of future cash payments.
In addition, these financial statements have been prepared using the accrual
basis of accounting.
GOING CONCERN
The Directors have considered the going concern assessment period of up to 31
December 2025 (the "going concern period"). The Group regularly monitors its
cash, funding and liquidity position. Near-term cash projections are revised
and underlying assumptions reviewed, generally monthly, and longer-term
projections are also updated regularly.
The Group's operational and financial planning is primarily based on a formal
work programme and budget plan for the current year, which is assessed and
finalised at the end of the prior year, and a rolling three-year plan. The
work programme and budget are supplemented by regular reforecasts throughout
the current year. Under the Base Case, outlined below, the Group maintains
sufficient liquidity over the 18 months from the balance sheet date of these
unaudited financial statements.
The going concern assessment for the next 18 months is based on oil prices in
line with the range of recent spot Brent prices, the Group's current oil price
hedging programme, and 2025 operational activity from the prevailing
three-year plan. This has been updated to reflect the current view on 2025
activity levels, particularly the Skua-11 well on the Montara asset, which is
currently planned for early 2025 and is expected to be the main element of the
2025 capital investment programme.
Downside scenarios were also constructed, to ensure that sufficient liquidity
is maintained in the event of oil prices c. 20% below the assumption in the
Base Case, combined with various operational riskings. Where liquidity is
reduced over the going concern period in these downside scenarios, the
Directors believe that several mitigating factors would be available to
increase liquidity, including but not limited to an extended working capital
facility, increased RBL capacity and/or reducing or deferring the Group's
planned expenditure. Consequently, the Directors believe that the Group
maintains sufficient liquidity over the 18 months from the date of these
unaudited financial statements.
Based on this analysis and assessment, the Directors believe that the Group is
well placed to manage its financing and other business risks satisfactorily.
The Directors have a reasonable expectation that the Group will have adequate
resources to continue in operation for at least 18 months from the date of
these unaudited condensed consolidated interim financial statements. They
therefore consider it appropriate to adopt the going concern basis of
accounting in preparing these financial statements.
Adoption of new and revised standards
New and amended IFRS standards that are effective for the current period
The Group has applied the following amendments that are relevant to the Group
for the first time with effect from 1 January 2024.
Amendments to IAS 1 Non-current liabilities with Covenants
Amendments to IAS 1 Classification of Liabilities as Current or Non-current
Amendments to IAS 1 Classification of Liabilities as Current or Non-current
Deferral of Effective Date
Amendments to IAS 7 and IFRS 7 Supplier Finance Arrangements
Amendments to IFRS 16 Lease liability in Sale and Leaseback
The amendments are effective for annual periods beginning on 1 January 2024
and require prospective application. The adoption of these amendments has
not resulted in changes to the Group's accounting policies.
3. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY
Critical accounting judgments and key sources of estimation uncertainty
In the application of the Group's accounting policies, management is required
to make judgments, estimates and assumptions about the carrying amounts of
assets and liabilities that are not readily apparent from other sources. The
estimates and associated assumptions are based on historical experience and
other factors that are considered to be relevant. Actual results may differ
from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are 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 key judgements and sources of estimation uncertainty remain the same as
disclosed in Jadestone's audited consolidated financial statements for the
year ended 31 December 2023.
4. OPERATING COSTS
Six months ended Six months ended Twelve months ended
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Production costs 132,668 87,615 225,270
Tariffs and transportation costs 3,656 3,035 7,502
Total production costs 136,324 90,650 232,772
Depletion and amortisation of oil and 29,959 17,243 60,396
gas properties
Depreciation of plant equipment and 8,221 7,331 15,745
right-of-use assets
Total depletion, depreciation and 38,180 24,574 76,141
amortisation
Corporate costs 14,274 8,433 17,072
Other operating expenses 38 13 5,769
Total other expenses 14,312 8,446 22,841
5. FINANCE COSTS
Six months ended Six months ended Twelve
months ended
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
Reclassified*
USD'000 USD'000 USD'000
Interest expense and others 3,414 5,626 11,460
Accretion expense 16,106 10,744 26,900
Warrants expense - 6,147 3,469
19,520 22,517 41,829
*Certain H1 2023 comparative information has been reclassified.
6. INCOME TAX EXPENSE/(CREDIT)
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Current tax
Corporate tax charge/(credit) 2,677 - (3,403)
(Over)/under provision in prior year (689) (2,176) 2,051
1,988 (2,176) (1,352)
Australian petroleum resource rent - - 1,735
tax ("PRRT")
Malaysian petroleum income tax 5,518 98 10,377
("PITA")
7,506 (2,078) 10,760
Deferred tax
Corporate tax (7,040) (8,833) (20,138)
PRRT (5,196) (231) (4,269)
PITA 6,720 801 2,155
(5,516) (8,263) (22,252)
1,990 (10,341) (11,492)
7. LOSS PER ORDINARY SHARE
The calculation of the basic and diluted loss per share is based on the
following data:
Six months ended Six months ended Twelve
months ended
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Loss for the purposes of basic (31,119) (59,934) (91,274)
and diluted per share, being the net
profit for the period attributable to
equity holders of the Company
Six months ended Six months ended Twelve
months ended
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Number Number Number
Weighted average number of ordinary 540,795,472 457,510,000 499,480,437
shares for the purposes of basic EPS
Effect of dilutive potential ordinary - - -
shares - share options
Effect of dilutive potential ordinary - - -
shares - performance shares
Effect of dilutive potential ordinary - - -
shares - restricted shares
Weighted average number of ordinary 540,795,472 457,510,000 499,480,437
shares for the purposes of diluted EPS
During the current period, 66,321 (H1 2023: 6,427,966, FY2023: 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 period/year.
During the current period, 76,356 (H1 2023: 326,477, FY2023: 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 period/year.
During the current period, 293,655 (H1 2023: 445,288, FY2023: 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 period/year.
During the current period, 30,000,000 (H1 2023: 3,977,901, FY2023: 17,095,890)
of weighted average contingently issuable shares under the Company's
restricted share plan were excluded from the calculation of diluted EPS, as
they are anti-dilutive in view of loss for the period/year.
Six months ended Six months ended Twelve
months ended
30 June 30 June 31 December
2024 2023 2023
Loss per share (US$) Unaudited Unaudited Audited
- - Basic and diluted (0.06) (0.13) (0.18)
8. ACQUISITION OF INTEREST IN CWLH JOINT OPERATION
8.1 Effective Date and Acquisition Date
On 14 November 2023, the Group executed a sale and purchase agreement ("SPA")
with Japan Australia LNG (MIMI) Pty Ltd ("MIMI"or "Seller") to acquire MIMI's
non-operated 16.67% working interest in the Cossack, Wanaea, Lambert and
Hermes oil field development (the "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 operators 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 that
the final payment will be US$18.8 million, payable at the end of December
2024.
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 net
cash receipt of US$5.2 million at completion. On 17 May 2023, 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 provisional fair
value of the assets and liabilities associated with the CWLH Assets as at the
Acquisition Date.
8.2 Acquisition of a 16.67% non-operated working interest
The CWLH Assets contain inputs (working interest in the CWLH Assets) and
processes (existing workforce and onshore and offshore infrastructures managed
by the operator), which when combined has the ability to contribute to the
creation of outputs (oil). Accordingly, the CWLH Assets constitute a
business and as a consequence, we have accounted for our acquisition of a
16.67% working interest in those assets using the accounting principles of
business combinations accounting as set out in IFRS 3, and other IFRSs as
required by the guidance in IFRS 11 paragraph 21A.
A purchase price allocation exercise was performed to identify, and measure at
fair value, the assets acquired and liabilities assumed in the business
combination. The consideration transferred was measured at fair value. The
Group has adopted the definition of fair value under IFRS 13 Fair Value
Measurement to determine the fair values, by applying Level 3 of the fair
value measurement hierarchy.
8.3 Fair value of consideration
After taking into account various adjustments the net consideration for the
CWLH Assets resulted in a cash receipt of US$5.2 million, as set out below:
USD'000
Asset purchase price 9,000
Closing statement adjustments (14,236)
Net cash receipts from the acquisition (5,236)
The Group considers that the purchase consideration and the transaction terms
to be reflective of fair value for the following reasons:
· Open and unrestricted market: there were no restrictions in place
preventing other potential buyers from negotiating with seller during the
sales process period and there were a number of other interested parties in
the formal sale process;
· Knowledgeable, willing and non-distressed parties: both the Group
and Seller are experienced oil and gas operators under no duress to buy or
sell. The process was conducted over several months which gave both parties
sufficient time to conduct due diligence and prepare analysis to support the
transaction; and
· Arm's length nature: the Group is not a related party to Seller.
Both parties had engaged their own professional advisors. There is no reason
to conclude that the transaction was not transacted at arm's length.
8.4 Assets acquired and liabilities assumed at the date of acquisition
During the period, the Group has adjusted the provisional fair values of the
identifiable assets and liabilities assumed as at Acquisition Date were:
Below are the effects of the provisional PPA adjustments in accordance with
IFRS 3:
Provisional PPA
USD'000
Asset
Non-current asset
Oil and gas properties (Note 10) 12,730
Deferred tax assets 19,763
Current asset
Amount due from joint arrangement partner 194
Trade and other receivables 45,770*
78,457
Liabilities
Non-current liabilities
Provision for asset restoration obligations (Note 18) 65,881
Deferred tax liabilities 17,812
83,693
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$45.8 million,
measured at the market price as at closing based on the March 2024 lifting of
US$86.28/bbl. The underlift position was recognised as an expense in
production cost, following a lifting which occurred in March 2024.
Due to the size, complexity and timing of the acquisition, the valuation
process is ongoing and is expected to be completed in H2 2024.
8.5 Impact of acquisition on the results of the Group
The Group's H1 2024 results included US$56.4 million of revenue and US$2.5
million of after tax profit attributable to the 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 Jan 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$24.9million.
9. INTANGIBLE EXPLORATION ASSETS
Total
USD'000
Cost
As at 1 January 2023 77,928
Additions 802((a))
As at 30 June 2023 78,730
Additions 834((a))
As at 31 December 2023 79,564
Additions 876((a))
As at 30 June 2024 80,440
Net book value
As at 30 June 2023 (unaudited) 78,730
As at 31 December 2023 (audited) 79,564
As at 30 June 2024 (unaudited) 80,440
((a) ) For the purpose of the Condensed Consolidated Statement of Cash Flows,
current period expenditure on intangible exploration assets of US$0.4 million
remained unpaid as at 30 June 2024 (H1 2023: US$0.4 million, FY2023: US$0.1
million).
10. OIL AND GAS PROPERTIES, PLANT AND EQUIPMENT AND
RIGHT-OF-USE ASSETS
Oil and gas properties Plant and equipment Right-of-use assets
Total
Production assets Development assets
USD'000 USD'000 USD'000 USD'000 USD'000
Cost
As at 1 January 2023 693,458 36,935 11,190 49,743 791,326
(Restated)*
Additions 1,677 21,026 302 36,827 59,832
Transfer of 50% 48,604 - - - 48,604
interest in PNLP Assets
Written off - - - (1,584) (1,584)
As at 30 June 2023 743,739 57,961 11,492 84,986 898,178
(Restated)*
Changes in asset 7,150 - - - 7,150
restoration obligations
Transfer of 50% (174) - - - (174)
interest in PNLP Assets
Additions 30,381 60,646 214 1,330 92,571
Written off (3,067) - - (38,089) (41,156)
Transfer - - 3,122 - 3,122
As at 31 December 778,029 118,607 14,828 48,227 959,691
2023
Additions 4,195((a)) 42,256((a)) 291 - 46,742
Acquisition of additional 12,730((b)) - - - 12,730
16.67% of CWLH Assets
Adjustment - - - (661) (661)
As at 30 June 2024 794,954 160,863 15,119 47,566 1,018,502
Accumulated depletion,
depreciation,
amortisation and
impairment
As at 1 January 2023 296,748 - 3,872 41,550 342,170
(Restated)*
Charge for the period 26,800 - 291 7,040 34,131
Impairment 48,604 - - - 48,604
Written off - - - (1,584) (1,584)
As at 30 June 2023 372,152 - 4,163 47,006 423,321
(Restated)*
Charge for the period 37,775 - 203 8,211 46,189
Impairment 29,507 - - - 29,507
Written off - - - (38,089) (38,089)
As at 31 December 439,434 - 4,366 17,128 460,928
2023
Charge for the period 36,194 - 245 7,976 44,415
As at 30 June 2024 475,628 - 4,611 25,104 505,343
*Certain H1 2023 comparative information has been restated. Please refer to
Note 26.
Oil and gas properties Plant and equipment Right-of-use assets
Total
Production assets Development assets
USD'000 USD'000 USD'000 USD'000 USD'000
Net book value
As at 30 June 2023 371,587 57,961 7,329 37,980 474,857
(unaudited)
(Restated)*
As at 31 December 338,595 118,607 10,462 31,099 498,763
2023 (audited)
As at 30 June 2024 319,326 160,863 10,508 22,462 513,159
(unaudited)
((a) ) For the purpose of the Condensed Consolidated Statement of Cash Flows,
current period expenditure on oil and gas properties of US$15.8 million
remained unpaid as at 30 June 2024 (H1 2023: nil, 2023: US$3.4 million).
Additionally, included in the oil and gas properties is the capitalisation of
borrowing costs relating to the Akatara development project of US$4.3 million
(H1 2023: nil, FY2023: US$2.4 million).
((b) ) On February 14, 2024, the Group obtained additional non-operated
16.67% working interest in Cossack, Wanaea, Lambert and Hermes oil field
development (the "North West Shelf Project" or "CWLH Asset"), offshore
Australia. As a result, the Group's non-operated interest in CWLH fields has
increased to 33.33% (from 16.67%) as disclosed in Note 8.
*Certain H1 2023 comparative information has been restated. Please refer to
Note 26.
11. INVESTMENT IN ASSOCIATE
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
At beginning of period/year 26,651 - -
Acquisition of 9.52% non-operated interest in - 27,853 27,853
Sinphuhorm Assets
Dividends received during the period/year (3,768) - (3,842)
Share of profit of the associate 2,124 - 2,640
At end of period/year 25,007 27,853 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. The acquisition included a 27.2% interest in APICO LLC, which
operates the Sinphuhorm concessions (E5N and EU1) and Dong Mun (L27/43). The
acquisition was completed on 23 February 2023, for a cash consideration of
US$27.9 million. The acquisition has an economic effective date of 1 January
2022, which meant the Group was entitled to net cash generated since effective
date to completion date.
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 associates' financial
statements which holds a 35% interest in the Sinphuhorm gas field. The APICO
LLC's financial statements are prepared in accordance with IFRS Accounting
Standards.
30 December 2023
30 June 2024 30 June 2023 Audited
Unaudited Unaudited USD'000
USD'000 USD'000
Current assets 29,885 32,754 39,027
Non-current assets 127,552 142,455 133,037
Current liabilities 18,343 15,501 27,048
Non-current liabilities 5,170 8,213 6,902
Revenue 38,565 22,388 59,504
Profit before tax 18,969 10,218 26,412
Profit after tax, representing total 7,808
comprehensive income for the year 7,086 9,705
Proportion of the Group's ownership 27.2%
interest in the associate 27.2% 27.2%
Share of profit of the associate 2,124 - 2,640
Dividends received from the associate during (3,768)
the year - (3,842)
12. TRADE AND OTHER RECEIVABLES
30 June 30 June 31 December 2023
2024 2023
Unaudited Unaudited Audited
Restated*
USD'000 USD'000 USD'000
Current
Trade receivables 9,274 6,388 12,533
Prepayments 6,709 7,064 5,947
Other receivables and deposits 2,334 50,945 88,005
Amount due from joint arrangement 3,493 2,589 12,911
partners (net)
Underlift crude oil inventories 9,771 4,651 3,539
VAT/GST receivables 1,311 1,079 1,444
Malaysia supplementary payment receivable 462 - -
33,354 72,716 124,379
Non-current
Other receivables 244,337 181,798 127,730
VAT receivables 18,156 9,329 14,130
262,493 191,127 141,860
295,847 263,843 266,239
The increase in non-current other receivables during the period reflects an
additional US$65.0 million payment into the CWLH abandonment trust fund,
following the acquisition of an extra 16.67% non-operated working interest in
CWLH assets. Additionally, US$47.8 million was reclassified from current to
non-current assets due to the deferral of decommissioning activities for the
PNLP CESS funds.
*Certain H1 2023 comparative information has been restated. Please refer to
Note 26.
13. CASH AND BANK BALANCES
30 June 30 June 31 December 2023
2024 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Cash and bank balances, representing cash
and cash equivalents in the consolidated
statement of cash flows, presented as:
Non-current 1,356 1,000 1,008
Current 129,513 117,782 152,396
130,869 118,782 153,404
The non-current cash and cash equivalents represents the restricted cash
balance of US$0.7 million (H1 2023: US$0.7 million), US$0.3 million (H1 2023:
US$0.3 million) and US$0.4 million (H1 2023: nil) in relation to deposits
placed for bank guarantees with respect to the PenMal Assets, Australian
office building, and Indonesia office building respectively. The bank
guarantees are expected to be in place for a period of more than twelve
months.
As part of the RBL facility, the Group must retain an aggregate amount of
principal, interest, fees and costs payable for the next two quarters in the
debt service reserve account ("DSRA"). An amount of US$8.2 million was
deposited into the DSRA during 2023. The DSRA is to cover every six-month
period obligation of the Group, hence classified as current cash and bank
balances.
14. SHARE CAPITAL AND SHARE PREMIUM ACCOUNT
Share Share premium account
capital
No. of shares USD'000 USD'000
Issued and fully paid
As at 1 January 2023 448,353,663 339 983
Issued during the period 94,283,543 120 50,844
Vesting of 2020 performance shares 79,327 - -
Vesting of 2020 restricted shares 101,063 - -
Share repurchased (2,051,022) (3) -
As at 30 June 2023/31 December 2023 540,766,574 456 51,827
Vesting of 2021 restricted shares 50,570 - -
As at 30 June 2024 540,817,144 456 51,827
The Company has one class of ordinary share. Fully paid ordinary shares with
par value of £0.001 per share carry one vote per share without restriction
and carry a right to dividends as and when declared by the Company.
15. MERGER RESERVE
The merger reserve arose from the difference between the carrying value and
the nominal value of the shares of the Company, following completion of the
internal reorganisation in 2021.
16. CAPITAL REDEMPTION RESERVE
The capital redemption reserve arose from the share buyback programme launched
by the Company in August 2022. It represents the par value of the shares
purchased and cancelled by the Company under the share buyback programme.
17. HEDGING RESERVE
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
At beginning of the period/year 14,131 - -
Loss arising on changes in fair value of hedging 34,440 10,985 30,509
instruments during the period/year
Income tax related to loss recognised in other (10,332) (2,160) (9,153)
comprehensive income
Net loss reclassified to profit or loss (15,425) - (10,322)
Income tax related to amounts reclassified to 4,628 - 3,097
profit or loss
At end of the period/year 27,442 8,825 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.
18. PROVISIONS
30 June 30 June 31 December 2023
2024 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Non-current
Asset restoration obligations 681,484 573,161 501,091
Others 1,431 8,464 2,079
682,915 581,625 503,170
Current
Asset restoration obligations - 9,551 102,811
Others 11,994 7,390 5,714
11,994 16,941 108,525
694,909 598,566 611,695
The total provisions for asset restoration obligations, both current and
non-current, increased by US$77.6 million during the period, primarily driven
by the addition of a 16.67% non-operated working interest in the CWLH Assets,
amounting to US$65.9 million, and US$1.3 million related to the Akatara gas
facility. The Group also recognised an accretion expense of US$10.4 million
during the period.
Additionally, US$102.8 million of ARO related to the PNLP assets was
reclassified from current to non-current reflecting the deferral of activities
to 2038 under the Puteri Cluster SFA PSC.
19. BORROWINGS
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Non-current secured borrowings
Reserve based lending facility 169,135 82,194 147,313
Current secured borrowings
Reserve based lending facility 29,829 22,802 7,260
198,964 104,996 154,573
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 2 (which is expected
later).
The borrowing base 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 of which completed in
February 2024. The borrowing base as at 30 June 2024 was US$200 million.
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 RBL facility pays interest at 450 basis points over the secured overnight
financing rate (SOFR), plus the applicable credit spread. The Group also
pays customary arrangement and commitment fees.
On 4 March 2024, the Group executed an additional drawdown of US$43.0 million
from the RBL facility and subsequently increased the loan balance to US$200.0
million for the period ending 30 June 2024, compared to a total USD$157.0
million drawdown as at 31 December 2023.
For the period ending 30 June 2024, the loans had an amortised carrying value
of US199.0 million. During H1 2023, the Group incurred total accretion
expenses of US$9.6 million and US$0.1 million of commitment fees, of which
US$4.3 million has been capitalised as disclosed in Note 10. The net accretion
expenses of US$5.3 million and US$0.1 million commitment fees were recorded as
finance cost in Note 5.
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 matures on 31 December 2024. The facility carries
interest of 15% on drawn amounts and 5% on undrawn amounts and can be repaid
or cancelled without penalties. The standby working capital facility
remained undrawn as at 30 June 2024 and at the date of signing the financial
statements.
20. TRADE AND OTHER PAYABLES
30 June 30 June 31 December 2023
2024 2023 Audited
Unaudited Unaudited USD'000
USD'000 USD'000
Current
Trade payables 17,268 24,539 36,056
Other payables 12,658 15,506 9,100
Accruals 54,662 32,215 56,534
Contingent payments - - 2,000
Malaysian supplementary payment payables - 732 2,152
Amount due to joint arrangement partner 3,138 433 1,252
Overlift crude oil inventories - - 6,004
GST/VAT payables 655 327 881
88,381 73,752 113,979
Non-current
Other payable 16,917 29,014 16,917
Accrual 420 - 49
17,337 29,014 16,966
105,718 102,766 130,945
21. DERIVATIVE FINANCIAL INSTRUMENTS
The Group uses derivatives to manage its exposure to oil price fluctuations.
Oil hedges are undertaken using swaps. All contracts are referenced to Dated
Brent oil prices. During the period, the Group entered into commodity swaps
that are designated as a cash flow hedge. All hedging undertaken during H1
2024 was deemed effective.
30 June 30 June 31 December
2024 2023 2023
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Derivative financial liabilities
Designated as cash flow hedges
Commodity swap 41,659 10,985 24,612
Measured at fair value through profit and loss
Foreign exchange forward contracts - - 73
41,659 10,985 24,685
Analysed as:
Current 35,762 4,599 17,977
Non-current 5,897 6,386 6,708
41,659 10,985 24,685
The following is a summary of the Group's outstanding derivative contracts:
Fair value asset at Fair value asset at Fair value asset at
30 June 2024 30 June 2023 31 December
Unaudited Unaudited 2023
Contract quantity Type of contracts Hedge classification USD'000 USD'000 Audited
Terms Contract price USD'000
Contracts designated as cash flow hedges
50% of Commodity Oct Weighted Cash flow 41,659 10,985 24,612
Group's swap: swap 2023 - average price
planned component Sep of
2PD 2025 US$69.69/bbl
production (H1 2023:
US$70.09,
2023:
US$70.51)
Contracts that are not designated in hedge accounting relationship
To hedge Foreign Execution USD/MYR: 4.60 FVTPL - - 73
MYR162.5 exchange date: 02
million by forward February
selling MYR contracts 2024
for USD
22. WARRANTS LIABILITY
On 6 June 2023, as part of the underwritten placing of additional ordinary
shares, the Company entered into a warrant instrument with Tyrus Capital Event
S.A.M 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.
Every half-year, management applies the Black-Scholes option-pricing model to
estimate the fair value of the warrants. As of 30 June 2024, the fair value of
warrants liability was US$2.5 million as compared to the fair value of
warrants as of 31 December 2023 of US$3.5 million. The differences of the fair
value of warrants of US$1.0 million were recorded under other financial gains
in the Condensed Consolidated Statements of Profit and Loss and Other
Comprehensive Income as disclosed in page 24.
23. SEGMENT INFORMATION
Information reported to the Group's Chief Executive Officer (the chief
operating decision maker) for the purposes of resource allocation is focused
on two reportable/business segments driven by different types of activities
within the upstream oil and gas value chain, namely producing assets and
secondly development and exploration assets. The geographic focus of the
business is on Southeast Asia ("SEA") and Australia.
Revenue and non-current assets information based on the geographical location
of assets respectively are as follows:
Producing Exploration/
assets development
Australia SEA SEA Corporate Total
USD'000 USD'000 USD'000 USD'000 USD'000
Six months ended 30 June 2024 (unaudited)
Revenue
Liquids revenue 135,279 48,865 - - 184,144
Gas revenue - 916 - - 916
135,279 49,781 - - 185,060
Production cost (116,424) (19,900) - - (136,324)
DD&A (31,850) (6,078) (125) (127) (38,180)
Administrative staff (7,682) (2,553) (772) (4,750) (15,757)
costs
Other expenses (2,671) (3,075) (6,560) (2,006) (14,312)
Share of results of - 2,124 2,124
associate
Other income 6,293 126 11 349 6,779
Finance costs (13,927) (3,347) (297) (1,949) (19,520)
Other financial gains - 73 - 928 1,001
Loss before (30,982) 17,151 (7,743) (7,555) (29,129)
tax
Additions to non- 70,962 48,176 47,470 - 166,608
current assets
Non-current assets 323,862 301,122 256,956 515 882,455
Producing Exploration/
assets development
Australia SEA SEA Corporate Total
USD'000 USD'000 USD'000 USD'000 USD'000
Six months ended 30 June 2023 (unaudited) (Restated)*
Revenue
Liquids revenue 62,810 22,789 - - 85,599
Gas revenue - 1,061 - - 1,061
62,810 23,850 - - 86,660
Production cost (70,084) (20,566) - - (90,650)
DD&A (23,053) (1,257) (113) (151) (24,574)
Administrative staff (7,066) (3,169) (974) (4,329) (15,538)
costs
Other expenses (2,103) (1,111) (778) (4,454) (8,446)
Other income 4,299 56 - 435 4,790
Finance costs (6,856) (1,523) (1,283) (12,855) (22,517)
Loss before (42,053) (3,720) (3,148) (21,354) (70,275)
tax
Additions to non- 79,647 84,731 24,145 500 189,023
current assets
Non-current assets 405,968 200,042 139,126 28,431 773,567
Twelve months ended 31 December 2023 (Audited)
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)
DD&A (65,204) (10,397) (248) (292) (76,141)
Administrative staff (14,550) (5,060) (1,773) (8,814) (30,197)
costs
Other expenses (12,652) (3,363) (2,319) (4,507) (22,841)
Impairment of assets (17,410) (12,271) - - (29,681)
Share of results of - 2,640 - - 2,640
associate
Other income 9,990 192 7,684 989 18,855
Finance costs (22,611) (6,565) (2,274) (10,379) (41,829)
Loss before tax (66,846) (13,987) 1,070 (23,003) (102,766)
Additions to non- 86,403 54,576 90,611 703 232,293
current assets
Non-current assets 346,281 191,550 209,373 642 747,846
*Certain H1 2023 comparative information has been restated. Please refer to
Note 26.
Non-current assets in the table comprises oil and gas properties, intangible
exploration assets, right-of-use assets, investment in associate, other
receivables and prepayment, plant and equipment used in corporate offices and
cash and cash equivalents. Deferred tax assets are excluded from the segmental
note but included in the Group's consolidated statement of financial position.
Revenue arising from producing assets relates to the Group's single customer
with respect to oil sales in Australia, and a different single customer for
oil and gas sales in Malaysia. There is an active market for the Group's oil
and gas production.
24. CONTINGENT LIABILITIES
Commitment exploration well at block 46/07 PSC, Vietnam
The Block 46/07 PSC includes a commitment well as part of the second
exploration phase which began in 2014 and has been successfully extended three
times until 30 June 2024 based on the plan to incorporate the commitment well
into the broader Nam Du / U Minh development project. This project is
currently working towards finalizing a gas sales agreement with a Final
Investment Decision expected by mid 2025. On February 6, 2024, a request for a
further three-year extension was submitted to the industry regulator. This
request is still pending approval. Historically, such extension applications
have required significant processing time. Management remains confident that
approval will be secured before the year's end. However, if the extension is
not approved, the Group will be obligated to pay a minimum work commitment
penalty of US$10.0 million.
25. EVENTS AFTER THE REPORTING PERIOD
Puteri Cluster SFA PSC Awards
The Group has been awarded the Puteri Cluster SFA 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 PETRONAS and the
Group. With this in effect, the AAKBNLP and PM318 PSC is deemed relinquished
as at 30 June 2024.
Lemang PSC, Commencement of Akatara Contractual Gas
On 22 June 2024, when the Company announced mechanical completion of the
Akatara Gas Processing Facility (the "Facility") and the introduction of
reservoir gas into the Facility. On 31 July 2024, following successful packing
of the 17km export pipeline from the Akatara field, commercial gas sales into
the regional trunkline in Sumatra commenced at a rate of c.4.0 mmscfd, or
approximately 20% of the daily contracted quantity ("DCQ") under the Akatara
gas sales agreement.
26. RESTATEMENT AND RECLASSIFICATION OF COMPARATIVE FIGURES
Certain comparative figures in the consolidated financial statements as at 30
June 2023 of the Group have been restated arising from a change in accounting
policy as well as reclassifications to conform to the presentation in the
current period and to better reflect the nature of the respective items in the
Group's consolidated financial statements.
The prior period restatements as at 31 December 2022 upon the finalisation of
the PPA for the acquisition of the CWLH Assets (the initial non-operated
16.67% working interest in CWLH Assets) in accordance with IFRS 3 generated
associated impacts to the oil and gas properties, accumulated losses, ARO
provision and overlift balances. The adjustments to the PPA values of the CWLH
Assets' oil and gas properties and ARO provision on the acquisition date of 1
November 2022 resulted to the adjustment to the depletion charges and ARO
accretion expense recognised in 2022 subsequent to the acquisition in the
consolidated statement of profit or loss. Additionally, following the
adoption of Amendments to IAS 12 Deferred Tax Related to Assets and
Liabilities Arising from a Single Transaction in 2023 which require the
deferred tax assets and deferred tax liabilities to be presented separately in
the balance sheet rather than offsetting against each other with additional
exclusions have been added to the initial recognition by the IASB. The
adoption of Amendments to IAS 12 has impacted the Group's recognition of
deferred tax assets and liabilities associated with the oil and gas properties
and ARO provision as at 31 December 2022.
Both of the above-mentioned restatement then impacted the opening and closing
balances of consolidated statement of financial position as at 30 June 2023
figures.
Reclassification was made relating to inventories in transit which were
reclassified from trade and other receivables to inventories. This
reclassification does not have impact on the net asset balance in the
consolidated statement of financial position and consolidated statement or
profit or loss nor on other comprehensive income.
Both of above-mentioned restatement and reclassification have been reflected
on the audited figured as of 31 December 2023.
The restatements and reclassification impact the following items:
As previously reported
USD'000 Restatements USD'000 As restated
USD'000
Consolidated statement of financial position as at
30 June 2023
Oil and gas properties 452,671 (23,123) 429,548
Deferred tax assets 2,963 13,725 16,688
Inventories 47,085 733 47,818
Trade and other receivables 73,049 (333) 72,716
Provisions - non-current 579,219 2,406 581,625
Deferred tax liabilities 71,828 1,800 73,628
Accumulated losses (113,805) (13,204) (127,009)
Consolidated statement of changes in equity for
the year ended 1 January 2023
Accumulated losses (51,787) (13,204) (64,991)
Additionally, reclassification made in the consolidated statement of cash
flows are related to the placement of decommissioning trust fund for the CWLH
Assets are now classified from investing activities to working capital in
accordance with the nature of activities. The reclassification does not have
impact in the consolidated statement of financial position and consolidated
statement or profit or loss nor on other comprehensive income.
As previously reported
USD'000 Reclassified USD'000 As reclassified
USD'000
Consolidated statement of cash flow for the six
months ended 30 June 2023
Increase in trade and other receivables (36,158) (41,000) (77,158)
Placement of decommissioning trust fund for 41,000
CWLH Asset (41,000) -
Glossary
£ British pound sterling
2P the sum of proved and probable reserves, reflecting those reserves with 50%
probability of quantities actually recovered being equal or greater to the sum
of estimated proved plus probable reserves
AAKBNLP Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields
AIM Alternative Investment Market
ARO Asset retirement obligations
API American Petroleum Institute gravity
bbl barrel
bbls/d barrels per day
boe barrels of oil equivalent
boe/d barrels of oil equivalent per day
DD&A depletion, depreciation and amortisation
EBITDAX earnings before interest tax, depreciation, amortisation and exploration
FPSO floating production storage and offloading
GHG greenhouse gases
IFRS International Financial Reporting Standards
LPG Liquefied petroleum gas
mcf thousand cubic feet of natural gas
mm million
mmbbls million barrels
mmboe million barrels of oil equivalent
NOPSEMA National Offshore Petroleum Safety and Environmental Management Authority
opex operating expenditures
PETRONAS Petroliam Nasional Berhad
PITA Petroleum Income Tax
PRRT Petroleum Resource Rent Tax
PSC production sharing contract
RBL reserves based loan
reserves hydrocarbon resource that is anticipated to be commercially recovered from
known accumulations from a given date forward
US$ or USD United States dollar
The technical information contained in this announcement has been prepared in
accordance with the June 2018 guidelines endorsed by the Society of Petroleum
Engineers, World Petroleum Congress, American Association of Petroleum
Geologists and Society of Petroleum Evaluation Engineers Petroleum Resource
Management System.
A. Shahbaz Sikandar of Jadestone Energy plc, Group Subsurface Manager with a
Masters degree in Petroleum Engineering, and who is a member of the Society of
Petroleum Engineers and has worked in the energy industry for more than 25
years, has read and approved the technical disclosure in this regulatory
announcement.
The information contained within this announcement is considered to be inside
information prior to its release, as defined in Article 7 of the Market Abuse
Regulation No. 596/2014 which is part of UK law by virtue of the European
Union (Withdrawal) Act 2018, and is disclosed in accordance with the Company's
obligations under Article 17 of those Regulations.
1 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%.
2 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.
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