TIDMJSE
RNS Number : 8966M
Jadestone Energy PLC
19 September 2023
2023 Half Year Results
19 September 2023-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 2023 (the "financial
statements").
Management will host a conference call at 9:00 a.m. UK time
today, details of which can be found in the announcement below.
Key updates:
l Akatara development project on track to be 65% complete by
end-September and remains on budget and schedule for first gas in
H1 2024.
l The first well in the four well East Belumut infill drilling
programme offshore Malaysia has been drilled successfully and was
brought onstream at 2,800 bbls/d gross, significantly ahead of
expectations. The second well in the programme is now underway.
l Montara production has averaged 6,250 bbls/d since early
September, benefitting from the return to service of the second
production separator and additional wells on the Montara field.
l 2023 production guidance from April to December narrowed to
13,500 - 15,000 boe/d from (13,500 - 17,000 boe/d) reflecting
year-to-date production trends and the recent one month shut in at
Montara.
l 2023 underlying operating costs guidance expected to come in
at lower end of US$180.0 - 210.0 million range, reflecting
year-to-date trends and close monitoring of activity levels.
l 2023 capital expenditure guidance is narrowed to US$110.0 -
125.0 million, (from US$110.0 - 140.0 million), primarily
reflecting the Akatara development project and East Belumut
drilling being on budget.
l US$59.9 million loss after tax for the first half of 2023,
consistent with earlier disclosures and reflective of Montara being
shut in to late-March 2023 and the subsequent impact on first half
liftings.
l Net cash of US$7.8 million at 30 June 2023 reflects c.US$118.8
million of consolidated Group cash balances and US$111.0 million of
debt drawn at 30 June 2023 under the Group's reserves-based lending
("RBL") facility.
Paul Blakeley, President and CEO commented:
"The first half of 2023 was impacted by the ongoing shut-in of
Montara until late March, with few liftings and softer Brent
pricing, coincident with a period of heavy investment at Akatara
and elsewhere. We therefore acted decisively to maintain a robust
balance sheet by finalising the RBL in May and by raising an
additional gross $53 million of new equity in June. As a result of
these actions, we ended the first half in a strong liquidity
position which will support the business through Akatara first gas,
followed by a rapid return to net cash, likely within the following
12 months period. Notwithstanding the more recent shut in at
Montara, we expect a significantly better financial performance in
the second half of 2023, based on our planned lifting schedule, the
benefit of recent acquisitions and improved prevailing oil
prices.
It was disappointing to see Montara shut in again in July,
although we quickly identified the source of the defect in one of
the FPSO's tanks and restarted production, having implemented a key
change to our inspection processes. This was an important step
forward, correcting a small gap in our procedures and giving far
greater confidence in the work we are doing to restore the FPSO's
condition, resulting in higher uptime reliability at Montara. It is
also important that we take no short cuts, thereby ensuring that
safety and structural risks and any potential for a hydrocarbon
leak to sea are absolutely minimised. The provision of a small
storage tanker in the near-term enables us to safely continue
steady production operations during a period of limited tank
capacity on the Montara FPSO, thereby sustaining current production
from Montara at around 6,250 bbls/d.
I am very proud of the way in which the teams offshore and
onshore have worked so tirelessly to restore the condition of the
Montara Venture. We have chosen to adopt inspection levels and
processes that are far above industry standards and we will never
take short cuts on maintaining asset integrity.
The Akatara project has maintained progress to plan, with an
acceleration in recent months as most civil works are now
completed, storage tanks are well advanced and many of the
long-lead items now arriving at site. We are on track to be 65%
complete by the end of September, for commissioning activities to
begin in the first quarter next year, and first gas to be delivered
in first half of 2024, as promised.
The East Belumut infill drilling campaign commenced in August
with pre-drill expectations that the four wells combined will
deliver 2 - 2,500 bbls/d of gross production and an IRR of c.90%.
The results of the first well have significantly exceeded our
expectations, coming on stream in recent days at c.2,800 bbls/day
of dry oil. We do expect water cut to develop soon and for rates to
stabilise nearer 1,000 bbls/d of oil, but the early results are
very encouraging.
While it has been a difficult few months, we are working hard to
restore confidence in our operating model at Montara as well as
deliver the growth projects in our portfolio for 2024 and beyond.
The addition of new assets such as CWLH and Sinphuhorm, and new
production at Akatara, will increasingly insulate us from one-off
events at Montara, but I do believe we have significantly advanced
the case for greater reliability across the whole portfolio into
the future. We continue to assess further acquisition opportunities
that are consistent with our ambition of delivering growth,
ensuring we live within our means of cash flow and debt, and
believe we are at a turning point to restore reliability, growth
and a strong balance sheet."
Paul Blakeley
EXECUTIVE DIRECTOR,
PRESIDENT AND CHIEF EXECUTIVE OFFICER
2023 FIRST HALF RESULTS SUMMARY
USD'000 except where indicated H1 2023 H1 2022 FY 2022
-------------------------------------- --------- --------- ----------
Production, boe/day(1) 12,339 15,008 11,487
Realised oil price per barrel of
oil equivalent (US$/boe)(2) 86.15 109.52 103.85
Realised gas price per thousand
standard cubic feet
(US$/mscf) 1.41 2.03 1.63
Revenue 86,660 225,639 421,602
Production costs (restated(3) ) (90,650) (92,983) (250,700)
Adjusted unit operating costs per
barrel of oil equivalent
(US$/boe)(4) 40.27 25.71 37.49
Adjusted EBITDAX(4) (restated(3)
) (3,127) 130,930 161,929
(Loss)/Profit after tax (restated(3)
) (59,934) 43,545 8,522
(Loss)/Earnings per ordinary share:
basic and diluted (US$)
(restated(3) ) (0.13) 0.09 0.02
Operating cash flows before movement
in working capital
(restated(3) ) (24,179) 116,899 158,148
Capital expenditure 23,807 13,621 82,876
Net cash(4) 7,782 161,628 123,329
Operational and financial summary
l Production decreased by 18% year-on-year during H1 2023 to
12,339 boe/d (H1 2022: 15,008 bbls/d), primarily due to the shut-in
at Montara between August 2022 to March 2023 resulting in a
decrease of 4,578 bbls/d, partly offset by the acquisitions of CWLH
Assets adding 1,569 bbls/d and Sinphuhorm at 1,083 boe/d;
l Oil liftings totalled 1.0 mmbbls in H1 2023 and were 51% lower
year-on-year, primarily due to the shut-in at Montara and the later
phasing of liftings from the PenMal Assets;
l The average realised oil price(1) in H1 2023 was US$86.15/bbl,
21% lower than H1 2022, largely due to lower realised Brent prices
year-on-year. The premium achieved in H1 2023 was US$8.87/bbl (H1
2022: US$6.99/bbl) due to relatively high proportion of Stag
liftings during H1 2023;
l H1 2023 revenue totalled US$86.7 million, a 62% decrease on H1
2022, reflecting lower lifted volumes and price realisations as
described above;
l At 30 June 2023, closing crude inventories totalled 421,720
bbls, and the Group had an underlift position of 117,318 bbls. Post
reporting period end, Montara lifted 0.3 mmbbls in mid-July which
generated US$24.3 million of revenues;
l Production costs decreased by 3% in the period to US$90.7
million (H1 2022: US$93.0 million) predominately due to a credit
for inventory changes and lower supplementary payments in Malaysia
offsetting the inclusion of CWLH operating costs and higher tanker
cost and fuel charges at Stag and Montara;
l Adjusted EBITDAX decreased to a loss of US$3.1 million (H1
2022: profit of US$130.9 million), mostly due to lower
revenues;
l Net loss after tax in H1 2023 of US$59.9 million (H1 2022:
US$43.5 million net profit);
l Operating cash outflow before movements in working capital in
H1 2023 of US$24.2 million (H1 2022: cash inflows of US$116.9
million), reflecting the trends described above;
l Capital expenditure in H1 2023 of US$23.8 million, an increase
of 75% compared to H1 2022 primarily due to the ramp up of
activities at the Akatara development project onshore Indonesia;
and
l Net cash balance of US$7.8 million as at 30 June 2023 (H1
2022: US$161.6 million), reflecting the operating cash outflows
during H1 2023, drawdown of the Group's reserves-based loan and the
proceeds from the equity placing and open offer in June 2023.
Significant events
l On 19 January 2023, the Group executed a sale and purchase
agreement with Salamander Energy (S.E. Asia) Limited (the
"Seller"), an affiliate of PT Medco Energi Internasional Tbk, to
acquire the Seller's 9.52% non-operated interest in the producing
Sinphuhorm gas field and a 27.2% interest in the Dong Mun gas
discovery onshore northeast Thailand (the "Sinphuhorm Assets");
l On 17 February 2023, the Group closed a US$50.0 million debt
facility ("Interim Facility") with two international banks to
provide additional liquidity prior to closing the reserves-based
lending facility ("RBL"). The loan was fully repaid on 1 June
2023;
l On 22 May 2023, the Group announced the closing of a US$200.0
million RBL facility with a group of four international banks (the
"RBL Banks"). The first drawdown of US$111.0 million occurred in
June and was used to repay the Interim Facility and to fund the
Group's operations and capital investment programme;
l As required by the RBL facility, at 30 June 2023, the Group
had entered into oil price swap contracts for 4.2 mmbbls,
representing approximately 78% of the required hedging volumes, at
a weighted average price of US$70.29/bbl. The hedging programme was
subsequently completed in July 2023, with 5.5 mmbbls hedged over
the Q4 2023 to Q3 2025 period at an overall weighted average price
of US$70.57/bbl; and
l On 6 June 2023, the Company raised US$51.1 million (net of
costs) through an equity placing and open offer of 94,081,826
ordinary shares at a price of GBP0.45 per share. The offer was
underwritten by Tyrus Capital Events S.a.r.l. ("Tyrus"), the
Company's largest shareholder. In connection with the underwriting,
Tyrus received warrants for 30 million ordinary shares with an
exercise price of GBP0.50 per share and exercisable any time within
36 months from the date of issue. In addition, the Company entered
into a standby working capital facility agreement with Tyrus to
provide financial flexibility and balance sheet resilience. The
standby working capital facility closed at US$31.9 million and has
an expiry date of 31 December 2024. The standby working capital
facility remains undrawn.
2023 Guidance
l Production: Guidance for the period April to December 2023 is
narrowed to 13,500 - 15,000 boe/d (from 13,500 - 17,000 boe/d),
reflecting year-to-date trends in production and the recent one
month shut in at Montara. The revised range for April to December
2023 is equivalent to an annual 2023 guidance range of 12,600 -
13,700 boe/d;
l Operating costs : Underlying operating costs are expected to
come in at the lower end of the US$180.0 - 210.0 million guidance
range, reflecting year-to-date trends and close monitoring of
activity levels. As disclosed previously, underlying operating cost
guidance excludes non-recurring items and certain costs such as
workovers, transportation, and expenditure associated with
non-producing assets offshore Malaysia. These excluded items are
included in the reported production costs in the Group's statement
of profit or loss, and are expected to total US$65.0 - 75.0 million
in 2023 ; and
l Capital expenditure: Capital expenditure guidance is narrowed
to US$110.0 - 125.0 million (from US$110.0 - 140.0 million),
reflecting expenditure at the Akatara development project and the
East Belumut drilling campaign progressing in line with plan, along
with some rephasing of spend on projects across the Group's
portfolio. Capital expenditure guidance excludes abandonment
expenditure associated with the PNLP Assets offshore Malaysia,
which is expected to total c.US$15.0 million in 2023. This figure
is expected to be partially recovered through existing cess funds
in 2024.
(1) Production includes the Sinphuhorm Asset gas production in
accordance with Petroleum Resource Management Systems guidelines,
however in accordance with IAS 28 the investment is accounted for
as an associated undertaking and only 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.
(3) Certain H1 2022 comparative information has been restated.
Please refer to Note 25 in the unaudited condensed consolidated
interim financial statements.
(4) Adjusted unit operating costs per boe, adjusted EBITDAX and
net cash are non-IFRS measures and are explained in further detail
on the Non-IFRS Measures section in this document.
Enquiries
Jadestone Energy plc.
Paul Blakeley, President and CEO +65 6324 0359 (Singapore)
Bert-Jaap Dijkstra, CFO
Phil Corbett, Investor Relations Manager + 44 7713 687 467 (UK)
ir@jadestone-energy.com
Stifel Nicolaus Europe Limited (Nomad, +44 (0) 20 7710 7600
Joint Broker) (UK)
Callum Stewart / Jason Grossman / Ashton
Clanfield
Jefferies International Limited (Joint +44 (0) 20 7029 8000
Broker) (UK)
Tony White / Will Soutar
Camarco (Public Relations Advisor) +44 (0) 203 757 4980
(UK)
Billy Clegg / Andrew Turner / Elfie jadestone@camarco.co.uk
Kent
Conference call and webcast
The Company will host an investor and analyst presentation at
9:00 a.m. (BST) on Tuesday, 19 September 2023, including a
question-and-answer session, accessible through the link below:
Webcast link:
https://www.investis-live.com/jadestone-energy/64e4883e0120c60d001e4a75/avdt
Event title: Jadestone Energy plc first-half 2023 results
Time: 9:00 a.m. (BST)
Date: 19 September 2023
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=54821
Access Code: 399289
ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG")
As a responsible upstream operator, Jadestone contributes to an
orderly energy transition by helping to meet regional Asia-Pacific
energy demand from existing, discovered resources, whilst
minimising the environmental footprint of its operations. Jadestone
believes that this strategy allows it to play an important role in
the energy transition - as larger oil and gas companies divest
their mid-life assets, Jadestone is well positioned to be the
steward of those assets through to the end of field life. In doing
so, Jadestone aims to bring positive social and economic benefits
for its stakeholders, local communities and people associated with
its operations.
Jadestone published its fourth Sustainability Report in June
2023, which covered the Group's ESG performance in 2022. The
section below provides an overview of H1 2023 performance of the
Group, representing the Stag and Montara fields, the PenMal
operated and producing assets and, where relevant, the Akatara gas
development.
Net Zero and GHG emissions
The Group pledged in June 2022 to achieve Net Zero Scope 1 and 2
GHG emissions from its operated assets by no later than 2040. The
detail of this pledge, as well as Jadestone's strategy through the
energy transition, can be found on Jadestone's website(1) . The
Group is on track to publish its Net Zero roadmap by the end of
2023 as it progresses feasibility studies for the shortlisted GHG
reduction options at its operated assets. In H1 2023, a concept
selection study was completed to evaluate options available in the
market to increase gas handling capacity of the compression systems
at one of the PenMal sites. A business case was submitted to
Jadestone's partner in Malaysia to seek approval for this project,
which is currently planned for implementation in H1 2025.
Similarly, a feasibility study of possible ways of increasing the
compression capacity at the Montara venture was undertaken, with
further trials being planned to determine next steps. Both
initiatives illustrate the Group's focus on minimising its flaring
related GHG emissions whilst maximising oil recovery.
HSE performance
The Group's priority remains the health and safety of its staff
and contractors, along with ensuring that any negative
environmental impacts from operations are minimised.
The Group reported zero recordable incidents during the first
half of 2023, and zero lost time injuries at the operated assets
and project sites. Of note, the Akatara gas development has
reported more than 1.9 million manhours without a recordable
injury, which contributed to the Group's seventh month without
recordable injury. Four high-potential events were recorded across
the Group in the period. The Group ensures that such events are
thoroughly investigated and corrective actions shared to ensure
learning and minimise the probability of reoccurrence.
Process safety continues to be a focus area, with zero Tier 1
loss of primary containment (LOPC) events reported during H1
2023.
With respect to environmental performance, the Group recorded
zero releases to the environment. O n the Montara Venture FPSO, a
phased production restart campaign commenced in March 2023. The
Group has progressed with the work related to the FPSO's cargo tank
integrity, with phase 2 inspections progressing well. In February
2023, the Group has announced that the General Direction issued by
the industry regulator, NOPSEMA, was closed, following NOPSEMA's
review of an independent assessment focusing on Jadestone's systems
for managing the structural integrity of the Montara Venture
FPSO.
Governance
Following an external review of the Board's performance during
2022, the Board is implementing a number of the recommendations
resulting from the review, to further ensure that the Group's
governance structure continues to improve, supporting the delivery
of strategy and the longer-term success of the Group. Acting on the
recommendations of the independent party has resulted in greater
direct dialogue amongst the Board, employees, shareholders and
other stakeholders, further strengthening Jadestone's alignment
with the principles of the QCA Code.
As previously reported, the Board believes that certain changes
are necessary to refresh its composition and adhere to best
practice by adding new experience to bolster the overall governance
framework of the Company. Two of the board's longest serving
directors, Iain McLaren, Independent Non-Executive Director and
Chair of the Audit Committee (who has served since 2015) and Robert
Lambert, Independent Non-Executive Director, Deputy Chairman and
Chair of the Health, Safety, Environment and Climate Committee (who
has served since 2011), have signalled their intention to step
down, once replacements have been appointed.
Furthermore, the Board and management team of Jadestone have
concluded that, given the significant growth and diversification of
the Group's operations in recent years, it is appropriate to
strengthen the senior management team and enhance internal
succession planning options by creating the role of Chief Operating
Officer (COO). A search for the new Non-Executive Directors and the
COO is well underway, with the current expectation that these
positions will be filled by early 2024.
(1)
https://www.jadestone-energy.com/jadestone-announces-2040-net-zero-target/
As disclosed on page 53 of the 2022 Annual Report, the Group
commenced its second and final phase of the internal reorganisation
which started in 2022. This phase of internal reorganisation
involves moving the Group's business activities from Canadian
sub-holding entities to a Singapore registered sub-holding entity.
The Group does not carry out any business activity in Canada, nor
it is not planning to in the future. The relevant intra-group
organisational changes are being executed at arm's length using
third-party expert advice, and will be completed in 2023.
OPERATIONAL REVIEW
Producing assets
Australia
Montara project
Montara production averaged 2,931 bbls/d for the first half of
2023 (H1 2022: 7,509 bbls/d).
There was one lifting during H1 2023 resulting in total sales of
0.2 mmbbls, compared to 1.3 mmbbls from three liftings during H1
2022. The premium realised in H1 2023 was US$1.36/bbl (H1 2022:
US$4.52/bbl). A further lifting was completed post-period in July
2023 for 0.3 mmbbls with a premium of US$2.01/bbl.
The Montara fields were shut in between August 2022 to March
2023 for storage tank inspection, maintenance and repair work
following a small release of oil to sea in June 2022 and a further
tank defect encountered in August 2022.
Following lifting of the General Direction issued by NOPSEMA in
September 2022 and the completion of tank inspection and repair
activities, as well as scheduled four-yearly maintenance
activities, a phased production restart campaign commenced in
late-March 2023. From restart up to 29 July 2023, Montara
production averaged approximately 6,100 bbls/d, with a maximum rate
of 8,100 bbls/d.
On 29 July 2023, production at Montara was temporarily shut in
following a hydrocarbon gas alarm in ballast water tank 4S.
Inspections identified the location of a small defect between tank
4S and oil cargo tank 5C, with repairs currently in progress.
Ballast water tank 4P was returned to service in early September
2023 following minor repairs.
Production restarted on 1 September 2023 and subsequently ramped
up to c.8,000 bbls/d (including flush production) after restart of
the FPSO's gas compression system. The field is currently producing
6,250 bbls/d, benefitting from the recent return to service of the
second production separator and Montara H2, H3 and H4 wells.
Stag oilfield
Production during H1 2023 was 2,879 bbls/d, compared to 2,057
bbls/d during H1 2022, with the increase due to the successful
completion and contribution of the 50H and 51H wells drilled in
November 2022.
There were two liftings during H1 2023, resulting in total sales
of 0.5 mmbbls, compared to 0.3 mmbbls in H1 2022 from one lifting.
The premiums realised in H1 2023 were US$19.10/bbl and
US$12.66/bbl, with an average premium of US$16.11/bbl (H1 2022:
US$23.72/bbl). The most recent Stag lifting in August 2023 realised
a premium of US$10.10/bbl.
North West Shelf Project
Production during H1 2023 was 1,569 bbls/d net to Jadestone's
working interest. There was no comparable production in H1 2022 as
the acquisition of the CWLH Assets was completed in November 2022.
Production net to Jadestone was 2,290 bbls/d between 1 November and
31 December 2022 and decreased in H1 2023 due to unplanned downtime
and a temporary shut-down of the FPSO due to Cyclone Ilsa.
Jadestone's next lifting is expected in Q4 2023.
Malaysia
PM 323, PM329, PM318 and AAKBNLP PSCs
During H1 2023, average production from the PM323 and PM329 PSCs
was 3,185 bbls/d of oil and 4,158 mscf/d of gas, creating a
combined production of 3,878 boe/d, net to Jadestone's working
interest (H1 2022: 4,578 bbls/d of oil, 5,191 mscf/d of gas,
combined production of 5,443 boe/d). The decrease in production was
predominately associated with natural field decline and higher
unplanned downtime as a result of the temporary closure of the
Chermingat platform due to operational issues.
There were three oil liftings during H1 2023, for total sales of
0.3 mmbbls in addition to the sale of 752.7 mmscf of gas, compared
to seven oil liftings during H1 2022, for total sales of 0.5 mmbbls
and sale of 939.7 mmscf of gas. The premium in H1 2023 ranged
between US$2.72/bbl and US$4.68/bbl with an average realised
premium of US$3.53/bbl. The latest liftings during July and August
2023 have achieved premiums of US$3.24/bbl and US$4.19/bbl,
respectively.
There was no production from the PM318 and AAKBNLP PSCs (the
"PNLP Assets") as facilities remained shut-in since the class
suspension of the Bunga Kertas FPSO in February 2022. In April
2023, the Group assumed operatorship of the PNLP Assets following
the decision of the previous operator to withdraw from the
licences. The Group believes there may be significant remaining
reserves on the licences and is evaluating redevelopment options
for the PSCs. The Group submitted a Business Value Proposition
("BVP") on 30 June 2023 for PETRONAS's approval. The BVP includes
an overview of the Group's plan of activities to reinstate
production from the PNLP Assets. If and when approved, the Group
will commence negotiation with PETRONAS on the PSC fiscal terms and
may subsequently seek Jadestone Board's approval prior to
sanctioning the project.
Thailand
APICO LLC (Sinphuhorm gas field and Dong Mun gas discovery)
On 19 January 2023, the Company announced the execution of the
sale and purchase agreement with Salamander Energy (S.E. Asia)
Limited, an affiliate of PT Medco Energy Internasional Tbk, to
acquire the Seller's 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 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). Due to a lack of influence
over the day-to-day operational activities at the Sinphuhorm
Assets, the Group does not recognise its share of revenues and
production costs, instead recognising dividend income when received
from APICO LLC. There was no dividend received during H1 2023. The
acquisition closed on 23 February 2023 for a cash consideration of
US$27.8 million, based on an effective date of 1 January 2022.
The acquisition added 4.6 mmboe of total proved plus probable
reserves, net to Jadestone, at the effective date of 1 January
2022.
Average production since the date of acquisition was 1,531
boe/d, equating to 1,083 boe/d for H1 2023.
Pre-production assets
Indonesia
Akatara field, Lemang PSC
The Lemang PSC is located onshore Sumatra, Indonesia. The PSC
contains the Akatara field, which has been substantially de-risked
with 11 wells drilled into the structure, and three years of oil
production history, up until the field ceased oil production in
December 2019. Jadestone is redeveloping Akatara field to supply
gas, condensate and LPGs for local and regional use.
The Akatara gas field has been independently estimated to
contain gross 2P reserves (before taking into account the local
government back-in right) of 71.1 bcf of sales gas, 2.2 mmbbls of
condensate and 8.4 mmboe of LPG, equating to a combined 22.5 mmboe
of resource. Jadestone has 100% interest in the Lemang PSC, with
the local government retaining a back-in right of up to 10%, which
is expected to be exercised prior to first gas.
Activity during the first half of 2023 focused primarily on
preparatory and civil works at the Akatara Gas Processing Facility
("AGPF"). The AGPF project is on track to be 65% complete by end of
September, and is currently focusing on major equipment
installation and integration with piping, and electrical
instrumentation. Key long-lead items have started to arrive at site
which will continue through November 2023. Commissioning activities
are expected to commence in Q1 2024 with commercial production
before the end of H1 2024.
In June 2023, the Group completed the successful reactivation of
two wells, the Akatara-1 (A1) and BWI-1 wells. Both wells were
reactivated from suspension status, with a production test at A1
and waste brine injection operation at BWI-1. The A1 well flowed at
a maximum rate of c.9 mmcf/d, with data from the well test
underpinning the current Akatara 2P reserves estimate. The A1 well
will provide pre-commissioning and commissioning gas for the AGPF
and BWI-1 is also ready to be utilised as an injector/disposal
well. A workover campaign for four wells is on schedule for Q4 2023
to Q1 2024 to deliver the gas production required to meet the daily
contract quantity under the gas sales agreement.
Vietnam
Block 51 and Block 46/07 PSCs
During the first half of 2023, the Group continued to negotiate
a heads of agreement for gas sales from the Nam Du/U Minh
development project. Following a gas sales agreement, the Group
would work to finalise the field development plan and submit this
for approval - a key step towards commercialising this significant
and strategic resource. In early August 2023, Jadestone's Chief
Executive Officer met with Vietnam's Prime Minister, who expressed
encouragement for Jadestone's development of the Nam Du/U Minh
fields and directed relevant stakeholders to support Jadestone on
progressing the development of the fields. Development of the Nam
Du/U Minh resource would help reduce energy shortages in Vietnam,
lessen future dependence on expensive LNG imports and would
contribute towards the country's energy transition and stated goal
of Net Zero greenhouse gas emissions by 2050.
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 2023.
Six Six Twelve
months months months
ended ended ended
30 June 30 June 31 December
USD'000 except where indicated 2023 2022 2022
----------------------------------------- ---------- ---------- -------------
Sales volume, barrels of oil equivalent
(boe) 1,119,011 2,199,583 4,326,770
Production, boe/day(1) 12,339 15,008 11,487
Realised oil price per barrel of
oil equivalent (US$/boe)(2) 86.15 109.52 103.85
Realised gas price per thousand
standard cubic feet
(US$/mscf) 1.41 2.03 1.63
Revenue 86,660 225,639 421,602
Production costs (restated(3) ) (90,650) (92,983) (250,700)
Adjusted unit operating costs per
barrel of oil equivalent,
(US$/boe)(4) 40.27 25.71 37.49
Adjusted EBITDAX(4) (restated(3)
) (3,127) 130,930 161,929
Unit depletion, depreciation &
amortisation (US$/boe) 13.15 12.06 10.80
Impairment of assets - - (13,534)
(Loss)/Profit before tax (restated(3)
) (70,275) 77,671 62,540
(Loss)/Profit after tax (restated(3)
) (59,934) 43,545 8,522
(Loss)/Earnings per ordinary share:
basic and diluted (US$)
(restated(3) ) (0.13) 0.09 0.02
Operating cash flows before movement
in working capital
(restated(3) ) (24,179) 116,899 158,148
Capital expenditure 23,807 13,621 82,876
Net cash(4) 7,782 161,628 123,329
Benchmark commodity price and realised price
The average realised oil price decreased in H1 2023 by 21% to
US$86.15/bbl, compared to US$109.52/bbl during H1 2022.
The primary driver of the decrease in the H1 2023 realised oil
price was the benchmark Brent price, which fell by 25% to
US$77.28/bbl, compared to H1 2022 at US$102.53/bbl. The average
realised premium for the period was US$8.87/bbl, compared to H1
2022 of US$6.99/bbl, due to the composition of liftings between the
periods, as H1 2023 contained relatively higher volumes of Stag
crude oil with a realised premium of US$16.11/bbl compared to the
realised premium of Montara with US$1.36/bbl.
(1) Production includes the Sinphuhorm Asset gas production in
accordance with Petroleum Resource Management Systems guidelines,
however in accordance with IAS 28 the investment is accounted for
as an associated undertaking and only 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.
(3) Certain H1 2022 comparative information has been restated.
Please refer to Note 25 in the unaudited condensed consolidated
interim financial statements.
(4) Adjusted unit operating cost per boe, adjusted EBITDAX and
net 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 for the period was 12,339 boe/d, compared
to 15,008 boe/d in H1 2022. The overall decrease of 2,669 bbls was
the result of the following factors:
-- Lower production (4,578 bbl/d) at Montara due to the shutdown
between August 2022 to March 2023; and
-- Decreased production (1,565 boe/d) from the PenMal Assets due
to higher unplanned downtime of the Chermingat platform and natural
field decline.
The above decrease was partly offset by:
-- A full period of the CWLH Assets contributing 1,569 bbls/d;
-- Sinphuhorm Assets contributing an average of 1,083 boe/d from
closing of the acquisition in February 2023; and
-- Stag production increased by 822 bbls/d due to the additional
production generated from successful drilling and completion of 50H
and 51H wells in November 2022.
There were six liftings during the period (H1 2022: 11),
resulting in sales of 1.0 mmbbls (H1 2022: 2.0 mmbbls). Lifted
volumes were lower predominately due to the shut-in at Montara,
which recorded one lifting in H1 2023 for 0.2 mmbbls, compared to
1.3 mmbbls from three liftings in H1 2022.
Stag recorded 0.5 mmbbls of liftings, compared to 0.3 mmbbls in
H1 2022.
PenMal Assets recorded 0.3 mmbbls of liftings in addition to the
sale of 752.7 mmscf of gas, compared to 0.5 mmbbls and sale of
939.7 mmscf of gas in H1 2022.
Revenue
The Group generated US$86.7 million of revenue in H1 2023,
compared to US$225.6 million during H1 2022, a decrease of 62%. The
decrease of US$139.0 million is due to:
-- Lower lifted volumes between the period generating a decrease of US$90.4 million;
-- Lower average realised oil prices of US$86.15/bbl (H1 2022:
US$109.52/bbl), contributing to a decrease of revenue by
US$47.7million; and
-- US$0.8 million lower gas sales at the PenMal Assets due to natural field decline.
Production costs
Production costs in H1 2023 were US$90.7 million (H1 2022:
US$93.0 million), a decrease of US$2.3 million predominately due to
a higher credit to production costs of US$16.1 million, lower
supplementary payments by US$11.5 million and lower operating costs
by US$6.5 million in the PenMal Assets. The decrease in production
costs was partly offset by higher operating costs of US$26.4
million incurred at Montara, Stag and the CWLH Assets. A more
detailed breakdown is provided below:
-- Closing inventory and underlift movements during H1 2023
generated a credit to production cost of US$24.9 million (H1 2022:
US$8.8 million). Montara and Stag had combined higher crude
inventories (H1 2023: increased by 331,039 bbls; H1 2022: increased
by 143,113 bbls) compared to the beginning of respective periods,
thus generating a credit of US$14.7 million (H1 2022: US$8.5
million). The underlift at the CWLH Assets further generated a
credit to production costs of US$10.1 million, as costs are matched
against lifting, which is scheduled for Q4 2023;
-- Supplementary payments and royalties decreased by US$10.3
million to a total of US$7.3 million, compared to US$17.6 million
in H1 2022. The supplementary payments at the PenMal Assets
decreased by US$11.5 million to US$5.5 million (H1 2022: US$17.0
million) due to the lower realised price compared to H1 2022 with
the payments based on the differential between the realised price
and the escalated PSC base price. The decrease was partly offset by
US$1.4 million of royalties paid by the CWLH Assets for the levy on
the wellhead value for a primary production licence (H1 2022:
nil);
-- PenMal Assets operating costs reduced by US$6.5 million to
US$2.8 million (H1 2022: US$9.3 million) following the production
suspension since February 2022 at the PNLP Assets . Operating costs
at PM323 and PM329 PSCs were stable comparing period-to-period;
-- Operating costs at Montara and Stag increased by US$17.8
million to US$41.1 million in H1 2023, compared to US$23.3 million
in H1 2022, with additional costs of US$6.1 million incurred at
Montara related to the hire of a crude tanker to compensate for
reduced FPSO tank capacity, and an additional US$5.0 million for
higher diesel consumption to power the compressor system during
shutdown of the FPSO's gas train. Stag tanker costs increased by
US$5.9 million compared to H1 2022 reflecting higher tanker rates
in H1 2023;
-- The CWLH Assets contributed an US$8.6 million increase in
production cost for H1 2023 compared to the same period last year
as the acquisition was completed in November 2022; and
-- Repair and maintenance ("R&M") costs increased by US$3.1
million to a total of US$28.4 million, compared to US$25.3 million
in H1 2022. The PenMal Assets incurred a total of US$6.8 million
(H1 2022: US$2.7 million) mostly reflecting the demobilisation work
on the FPSO at the PNLP Assets , repair work at the PM323 PSC
Chermingat platform during the temporary shutdown and the repair of
the gas turbine generator at PM329 PSC. This increase was partly
offset by US$1.0 million lower R&M costs incurred by the
Australian assets.
Adjusted unit operating cost per boe was US$40.27/bbl (H1 2022:
US$25.71/boe) (see Non-IFRS measures section below in this
document). The increase in adjusted unit operating cost is mostly
caused by the reduced production during the period at Montara and
the PenMal Assets combined with the increased tanker rates at Stag
during H1 2023.
Depletion, depreciation and amortisation ("DD&A")
The depletion charges of oil and gas properties were US$24.6
million in H1 2023, compared to US$35.1 million in H1 2022,
predominately due to the lower production at Montara. As a result,
the PenMal Assets and Stag represented a higher proportion of
production. The DD&A rate at Montara was US$23.64/bbl (H1 2022:
US$19.46/bbl) compared to Stag at US$19.05/bbl (H1 2021:
US$12.72/bbl) and PenMal US$1.49/bbl (H1 2022: US$1.61/bbl).
The depletion cost on a unit basis in H1 2023 was US$13.15/boe,
9% higher when compared to US$12.06/boe in H1 2022, mostly due to
an increase in the asset retirement obligations ("ARO") and the
addition of capital expenditure from drilling of the 50H and 51H
wells at Stag in Q4 2022.
Depreciation of the Group's right-of-use assets increased to
US$7.0 million in H1 2023 from US$6.1 million in H1 2022, primarily
due to the three-year lease extension for helicopters at Montara
which commenced in April 2023.
Other expenses
Other expenses increased during H1 2023 to US$8.4 million (H1
2022: US$5.5 million). The increase of US$2.9 million was
predominately related to advisory and consulting fees for business
development and the earlier reported internal reorganisation.
Finance costs
Finance costs in H1 2023 were US$22.5 million (H1 2022: US$4.8
million), an increase of US$17.7 million, predominately due to:
-- Warrants expense of US$6.1 million arose from the warrants
for 30 million ordinary shares received by Tyrus in connection with
the underwriting debt facility in support of the equity
placing;
-- ARO accretion expense increased by US$5.4 million to US$9.6
million compared to US$4.2 million in H1 2022, resulting from an
increase in the ARO at Stag and Montara as assessed at year-end
2022. The Group also incurred US$0.2 million of accretion expense
on Lemang PSC long-term VAT receivables;
-- Interest expense increased by US$2.6 million to US$2.7
million compared to US$0.1 million in H1 2022, mainly due to the
interest expense and fees associated with the US$50.0 million
Interim Facility (US$1.3 million) and relating to the RBL facility
(US$1.2 million). In addition, an upfront fee of US$2.2 million was
paid for the equity underwrite debt facility agreement (H1 2022:
nil) ;
-- Interest on lease liabilities increased by US$0.6 million to
US$1.0 million compared to US$0.4 million in H1 2022, mainly due to
the three-year lease extension for helicopters at Montara which
commenced in April 2023; and
-- Lemang PSC contingent payments contributed US$0.5 million
relating to the accretion of the present value of the
liability.
Taxation
The tax credit of US$10.3 million in H1 2023 (H1 2022: tax
charge of US$34.1 million) includes a current tax credit of US$2.1
million (H1 2022: tax charge of US$34.9 million) and a deferred tax
credit of US$8.2 million (H1 2022: US$0.8 million).
The tax paid during the period included US$1.3 million of
corporate tax payments and US$3.4 million of petroleum income tax
("PITA") tax in Malaysia.
The weighted average effective tax rate based on the countries
where the producing assets are located was 56% (H1 2022: 56%). The
consolidated group effective tax rate for the current period was
negative 15% (H1 2022: 44%) reflecting the Group's loss making
position.
Australia taxes
The Australian corporate income tax rate is 30% and Petroleum
Resource Rent Tax ("PRRT") is 40%, which is cash based and income
tax deductible. The combined standard effective tax rate is 58%,
while the actual effective tax rate for the current period is
negative 27% due to the combined net losses incurred from the
Australian operations, which predominately arose from the
production shut-in at Montara. The Australian operations recognised
a current tax credit of US$2.1 million relating to an overprovision
of tax expense in 2022. Additionally, a deferred tax credit of
US$8.8 million was recognised reflecting the loss incurred during
H1 2023 which can be carried forward to offset future taxable
profits.
Stag recognised a deferred PRRT tax credit of US$0.2 million due
to PRRT credits available from the augmentation(1) in H1 2023,
which can be utilised to offset future PRRT expense.
Malaysia taxes
Malaysian PITA is a PSC based tax on petroleum operations at the
rate of 38%. There are no other material taxes in Malaysia. The
PenMal Assets incurred a deferred PITA charge of US$0.8 million
which primarily arose from the timing differences of the accounting
and tax bases of the oil and gas properties.
(1) The PRRT credits were generated from the capital expenditure
incurred in Australia. The unutilised PRRT credits are augmented
(increased with inflation) at a rate approved by the Australian Tax
Office.
RECONCILIATION OF CASH
US$'000 H1 2023 H1 2022
------------------------------------- -------------------- --------------------
Cash and cash equivalent at
the beginning of
period 123,329 117,865
Revenue 86,660 225,639
Other operating income 3,324 3,528
Production costs (restated(1)
) (90,650) (92,983)
Administrative staff costs (15,080) (14,482)
Other expenses (8,433) (4,803)
---------
Operating cash flows before
movements in
working capital (24,179) 116,899
Movements in working capital
(restated(1) ) (30,377) (12,907)
Net tax paid (4,755) (34,177)
Purchases of intangible exploration
assets, oil and
gas properties, and plant
and equipment(2) (23,439) (13,364)
Cash paid for acquisition of
Sinphuhorm Assets (27,853) -
Placement of decommissioning
trust fund for
CWLH Assets (41,000) -
Placement of abandonment cess
fund for PenMal
Assets - (169)
Other investing activities 1,466 170
Net proceeds from issuance
of shares 51,070 670
Shares repurchased (2,084) -
Dividend paid - (6,241)
Repayment of lease liabilities (7,009) (6,518)
Total drawdown from borrowings 161,000 -
Repayment of borrowings (50,000) -
Financing activities (7,387) (600)
--------- ---------
Total cash and cash equivalent
at the end of
period 118,782 161,628
========= =========
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.
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.
(1) Certain H1 2022 comparative information has been restated.
Please refer to Note 25 in the unaudited condensed consolidated
interim financial statements.
(2) Total capital expenditure was US$23.8 million (H1 2022:
US$13.6 million), comprising total capital expenditure paid of
US$23.4 million (H1 2022: US$13.4 million) and accrued capital
expenditure of US$0.4 million (H1 2022: US$0.2 million).
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 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.
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
USD'000 except where indicated 2023 2022 2022
---------------------------------------- ----------- ----------- -------------
Production costs (reported)
(restated(1) ) 90,650 92,983 250,700
Adjustments
Lease payments related to
operating activities(2) 7,493 6,371 13,687
Underlift, overlift and crude
inventories
movement(3) (restated(1)
) 24,897 8,830 (39,436)
Workover costs(4) (9,531) (8,435) (10,190)
Other income(5) (2,584) (2,410) (5,030)
Non-recurring operational
costs(6) (11,565) - -
Non-recurring repair and maintenance(7) (312) (5,510) (13,761)
Transportation costs (3,035) (510) (8,341)
PenMal Assets supplementary
payments and
Australian royalties(8) (7,298) (16,731) (26,381)
PenMal non-operated assets
operational costs(9) (6,670) (4,748) (4,056)
Adjusted production costs 82,045 69,840 157,192
----------- ----------- -------------
Total production (barrels
of oil equivalent) 2,037,420 2,716,436 4,192,618
Adjusted unit operating costs
per barrel of oil
equivalent 40.27 25.71 37.49
=========== =========== =============
(1) Certain H1 2022 comparative information has been restated.
Please refer to Note 25 in the unaudited condensed consolidated
interim financial statements.
(2) 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.
(3) 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).
(4) Workover costs are excluded to enhance comparability. The
frequency of workovers can vary significantly, across periods.
(5) Other income represents the rental income from a helicopter
rental contract (a right-of-use asset) to a third party.
(6) Non-recurring operational costs in H1 2023 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, diesel fuel consumption by the FPSO during
production shutdown and to power the reinjection compressor during
production start-up. The Group also incurred charges associated
with short lifting a cargo and delivery delays.
(7) Non-recurring repair and maintenance costs in H1 2023
predominately related to the repair of a gas turbine generator at
the PenMal Assets PM329 PSC. The costs during H1 2022 predominately
related to Montara Skua-11 well subsurface repairs and Stag
structural marine maintenance and import hose replacement.
(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) PenMal non-operated assets operational costs in H1 2023
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. The costs in 2022 predominately related
to the costs incurred to repair the FPSO BUK at the PNLP Assets
following the suspension of class in February 2022.
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 follow:
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2023 2022 2022
USD'000 Restated(1)
Revenue 86,660 225,639 421,602
Production costs (restated(1)
) (90,650) (92,983) (250,700)
Administrative staff costs (15,538) (15,165) (29,218)
Impairment of assets - - (13,534)
Other expenses (8,446) (5,503) (22,305)
Other income, excluding interest
income 3,324 3,528 27,152
Other financial gains - 1,904 1,904
----------- ------------- --------------
Unadjusted EBITDAX (24,650) 117,420 134,901
Non-recurring
Impairment of assets - - 13,534
Non-recurring opex(2) 18,547 13,135 20,534
Insurance claim receipts(3) - - (17,977)
Change in provision - Lemang
PSC contingent
payments - - 7,333
Fair value loss on contingent
considerations 534 - 1,920
Others(4) 2,442 375 1,684
----------- ------------- --------------
21,523 13,510 27,028
----------- ------------- --------------
Adjusted EBITDAX (3,127) 130,930 161,929
=========== ============= ==============
(1) Certain H1 2022 comparative information has been restated.
Please refer to Note 25 in the unaudited condensed consolidated
interim financial statements.
(2) Non-recurring opex represents 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. The Group also incurred
charges associated with short lifting a cargo and delivery delays
and repair of a gas turbine generator at PM329 PSC. The H1 2022
non-recurring costs mainly consisted of Montara Skua-11 well
subsurface repairs and Stag structural marine maintenance and
import hose replacement .
(3) Insurance claim receipts for the full year ended 2022
represented insurance claim received at Montara for the
compensation for the loss of production relating to the Skua-11
well in 2020.
(4) Includes business development costs, transition team costs
relating to the terminated Maari acquisition and internal
reorganisation costs.
Net cash/debt
Net cash/debt 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
USD'000 2023 2022 2022
-------------------------- ----------- --------- -----------
Cash and cash equivalents 118,782 161,628 123,329
Borrowings (111,000) - -
----------- --------- -----------
Net cash/(debt) 7,782 161,628 123,329
=========== ========= ===========
Net cash/debt is defined as the sum of cash and cash equivalents
and restricted cash, less the outstanding principal sum of
borrowings.
On 17 February 2023, the Group closed the Interim Facility with
two international banks prior to closing the RBL facility. US$28.5
million of the Interim Facility was drawn in February 2023 to fund
the acquisition of the Sinphuhorm Assets. The second drawdown of
US$21.5 million occurred in May 2023 to fund the US$20.5 million
payment into the CWLH abandonment trust fund. The loan was fully
repaid on 1 June 2023.
On 22 May 2023, the Group announced the closing of a US$200.0
million RBL facility with the RBL Banks for the purpose of repaying
the Interim Facility and to fund the Group's operations and capital
investment programme, particularly the Akatara gas development
project onshore Indonesia . The facility incorporates standard
terms and conditions, including a parent company financial covenant
for a maximum total debt of 3.5 times annual EBITDAX, tested
bi-annually on 30 June and 31 December. The assets under the RBL
facility are required to hold a total minimum liquidity balance of
US$15.0 million and the Group needs to carry sufficient cash to
cover forward-looking capital expenditures for two quarters .
Under the RBL facility, the Group had drawn US$111.0 million as
at 30 June 2023. Cash and cash equivalents as at 30 June 2023 were
US$118.8 million, including the proceeds from the equity fundraise
on 6 June 2023, which generated a net cash position of US$7.8
million at the end of the period.
On 6 June 2023, the Company entered into a committed standby
working capital facility with Tyrus for a facility size of up to
US$35.0 million. The standby working capital facility closed at
US$31.9 million, after deducting US$3.1 million, representing the
gross proceeds of the equity fundraise in excess of US$50.0
million. The facility does not amortise and matures on 31 December
2024. The working capital 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 was undrawn
as at 30 June 2023.
2023 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 2023 remain unchanged from the risks disclosed
in the 2022 Annual Report pages 25 to 27. 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 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.
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
19 September 2023
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 2023
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Restated*
Notes USD'000 USD'000 USD'000
----------------------------------- ------ ----------- ----------- --------------
Consolidated statement
of profit or loss
Revenue 86,660 225,639 421,602
Production costs 4 (90,650) (92,983) (250,700)
Depletion, depreciation
and amortisation 4 (24,574) (35,135) (61,834)
Administrative staff costs (15,538) (15,165) (29,218)
Other expenses 4 (8,446) (5,503) (22,305)
Impairment of assets - - (13,534)
Other income 4,790 3,698 28,033
Finance costs 5 (22,517) (4,784) (11,408)
Other financial gains - 1,904 1,904
----------- ----------- --------------
(Loss)/Profit before tax (70,275) 77,671 62,540
Income tax credit/(expense) 6 10,341 (34,126) (54,018)
----------- ----------- --------------
(Loss)/Profit for the
period/year (59,934) 43,545 8,522
=========== =========== ==============
(Loss)/Earnings per ordinary
share
Basic and diluted (US$) 7 (0.13) 0.09 0.02
=========== =========== ==============
Other comprehensive loss
(Loss)/Profit for the period/year (59,934) 43,545 8,522
Items that may be reclassified
subsequently
to profit or loss:
Loss on unrealised cash (10,985) -
flow hedges -
Hedging gain reclassified - -
to profit or loss -
----------- ----------- --------------
(10,985) - -
Tax credit relating to
components of other
comprehensive loss 2,160 - -
----------- ----------- --------------
Other comprehensive loss (8,825) - -
Total comprehensive (loss)/income
for the
period/year (68,759) 43,545 8,522
=========== =========== ==============
*Certain H1 2022 comparative information has been restated.
Please refer to Note 25.
Condensed Consolidated Statement of Financial Position as at 30
June 2023
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Restated*
Notes USD'000 USD'000 USD'000
---------------------------------- ------ ---------- ---------- ------------
Assets
Non-current assets
Intangible exploration
assets 8 78,730 77,027 77,928
Oil and gas properties 9 452,671 350,404 456,768
Plant and equipment 9 7,329 8,896 7,318
Right-of-use assets 9 37,980 9,288 8,193
Investment in associate 10 27,853 - -
Other receivables and prepayment 11 191,127 46,817 90,590
Deferred tax assets 2,963 20,049 9,118
Cash and cash equivalents 12 1,000 621 676
---------- ---------- ------------
Total non-current assets 799,653 513,102 650,591
---------- ---------- ------------
Current assets
Inventories 47,085 38,162 18,911
Trade and other receivables 11 73,049 13,633 20,368
Tax recoverable 8,496 8,162 9,725
Cash and cash equivalents 12 117,782 161,007 122,653
---------- ---------- ------------
Total current assets 246,412 220,964 171,657
---------- ---------- ------------
Total assets 1,046,065 734,066 822,248
========== ========== ============
Equity and liabilities
Equity
Capital and reserves
Share capital 13 456 359 339
Share premium account 13 51,827 870 983
Merger reserve 14 146,270 146,270 146,270
Share based payments reserve 27,365 26,619 26,907
Capital redemption reserve 15 24 - 21
Hedging reserve 16 (8,825) - -
(Accumulated losses)/Retained
earnings (113,805) 2,281 (51,787)
---------- ---------- ------------
Total equity 103,312 176,399 122,733
---------- ---------- ------------
*Certain H1 2022 comparative information has been restated.
Please refer to Note 25.
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
---------------------------------- ------ ---------- ---------- ------------
Non-current liabilities
Provisions 17 579,219 413,451 508,539
Borrowings 18 82,194 - -
Lease liabilities 24,818 1,154 2,880
Other payable 19 29,014 - -
Derivative financial instruments 20 6,386 - -
Deferred tax liabilities 71,828 59,032 88,406
---------- ---------- ------------
Total non-current liabilities 793,459 473,637 599,825
---------- ---------- ------------
Current liabilities
Borrowings 18 22,802 - -
Lease liabilities 14,107 9,576 6,227
Trade and other payables 19 73,752 46,575 73,752
Derivative financial instruments 20 4,599 - -
Warrants liability 21 6,147 - -
Provisions 18 16,941 3,503 703
Tax liabilities 10,946 24,376 19,008
---------- ---------- ------------
Total current liabilities 149,294 84,030 99,690
---------- ---------- ------------
Total liabilities 942,753 557,667 699,515
---------- ---------- ------------
Total equity and liabilities 1,046,065 734,066 822,248
========== ========== ============
Condensed Consolidated Statement of Changes in Equity
for the six months ended 30 June 2023
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 2022 358 201 146,270 25,936 - - (35,023) 137,742
Profit for the
period,
representing
total
comprehensive
income for
the period - - - - - - 43,545 43,545
-------- -------- ----------- -------- ------------ ---------
Dividend paid - - - - - - (6,241) (6,241)
Share-based
payments - - - 683 - - - 683
Shares issued
(Note
13) 1 669 - - - - - 670
--------
Total
transactions
with owners,
recognised
directly
in equity 1 669 - 683 - - (6,241) (4,888)
-------- -------- -------- --------- ----------- -------- ------------ ---------
As at 30 June
2022
(Restated)* 359 870 146,270 26,619 - - 2,281 176,399
======== ======== ======== ========= =========== ======== ============ =========
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 2022 358 201 146,270 25,936 - - (35,023) 137,742
Profit for the
year,
representing
total
comprehensive
income for
the year - - - - - - 8,522 8,522
-------- ----------- -------- ------------ ---------
Dividends paid - - - - - - (9,216) (9,216)
Share-based
payments - - - 971 - - - 971
Shares issued
(Note
13) 2 782 - - - - - 784
Share
repurchased
(Note 13) (21) - - - 21 - (16,070) (16,070)
-------- -------- -------- --------- ----------- -------- ------------ ---------
Total
transactions
with owners,
recognised
directly
in equity (19) 782 - 971 21 - (25,286) (23,531)
-------- ----------- -------- ------------ ---------
As at 31
December
2022 339 983 146,270 26,907 21 - (51,787) 122,733
======== ======== ======== ========= =========== ======== ============ =========
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 339 983 146,270 26,907 21 - (51,787) 122,733
Profit for the
period,
representing
total
comprehensive
income for
the period - - - - - - (59,934) (59,934)
Other
comprehensive
loss for the
period - - - - - (8,825) - (8,825)
-------- -------- -------- --------- ----------- -------- ------------ ---------
Share-based
payments - - - 458 - - - 458
Shares issued
(Note
13) 120 50,844 - - - - - 50,964
Shares
repurchased
(Note 13) (3) - - - 3 - (2,084) (2,084)
-------- -------- -------- --------- ----------- -------- ------------ ---------
Total
transactions
with owners,
recognised
directly
in equity 117 50,468 - 458 3 - (2,084) 49,338
-------- -------- -------- --------- ----------- -------- ------------ ---------
As at 30 June
2023 456 51,827 146,270 27,365 24 (8,825) (113,805) 103,312
======== ======== ======== ========= =========== ======== ============ =========
Condensed Consolidated Statement of Cash Flows for the six
months ended 30 June 2022
Six months Six months Twelve
months
ended ended ended
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Restated*
Notes USD'000 USD'000 USD'000
------------------------------------ ------ ----------- ----------- ------------
Operating activities
(Loss)/Profit before tax (70,275) 77,671 62,540
Adjustments for:
Depletion, depreciation 4 /
and amortisation 9 24,574 35,135 61,834
Finance costs 5 22,517 4,784 11,408
Share-based payments 458 683 971
Allowance for slow moving
inventories 13 - 3,768
Interest income (1,466) (2,074) (881)
Provision for doubtful
debts - 446 -
Unrealised foreign exchange
loss - 241 245
Assets written off - 13 212
Impairment of oil and gas
properties - - 13,534
Change in provision - - 7,333
Accretion income on Australian
tax
repayment plan - - (1,904)
Reversal of impairment
of amount due from
joint arrangement partner - - (912)
Operating cash flows before
movements in
working capital (24,179) 116,899 158,148
(Increase)/Decrease in trade
and other
receivables (36,158) 20,256 41,183
Increase in inventories (18,630) (10,774) (1,096)
Increase/(Decrease) in trade
and other
payables 24,411 (22,389) (2,471)
----------- ----------- ------------
Cash (used in)/generated
from operations (54,556) 103,992 195,764
Net tax paid (4,755) (34,177) (33,130)
----------- ----------- ------------
Net cash (used in)/generated
from operating
activities (59,311) 69,646 162,634
----------- ----------- ------------
*Certain H1 2022 comparative information has been restated.
Please refer to Note 25.
Six months Six months Twelve
months
ended ended ended
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
------------------------------------ ------ ----------- ----------- ------------
Investing activities
Cash paid for acquisition
of Sinphuhorm
Assets 10 (27,853) - -
Cash received from acquisition
of CWLH
Assets - - 5,750
Cash paid for acquisition
of 10% interest of
Lemang PSC - - (500)
Payment for oil and gas
properties 9 (22,703) (10,687) (78,938)
Payment for plant and equipment 9 (302) (253) (356)
Payment for intangible exploration
assets 8 (434) (2,424) (3,334)
Placement of decommissioning
trust fund for
CWLH Assets (41,000) - (41,000)
Placement of abandonment
cess fund for
PenMal Assets - (169) (397)
Interest received 1,466 170 881
----------- ----------- ------------
Net cash used in investing
activities (90,826) (13,363) (117,894)
----------- ----------- ------------
Financing activities
Net proceeds from issuance
of shares 51,070 670 784
Shares repurchased (2,084) - (16,070)
Dividends paid - (6,241) (9,216)
Total drawdown from borrowings 161,000 - -
Repayment of borrowings (50,000) - -
Repayment of lease liabilities (7,009) (6,518) (13,914)
Interest on lease liabilities
paid (1,027) (400) (769)
Interest on borrowings paid (793) - -
Payment for borrowings costs (5,535) - -
Interest paid (32) (200) (91)
Net cash generated from/(used
in) financing
activities 145,590 (12,689) (39,276)
----------- ----------- ------------
Net (decrease)/increase
in cash and cash
equivalents (4,547) 43,763 5,464
Cash and cash equivalents
at beginning of the
period/year 123,329 117,865 117,865
----------- ----------- ------------
Cash and cash equivalents
at end of the
period/year 118,782 161,628 123,329
=========== =========== ============
Explanation Notes to the Condensed Consolidated Interim
Financial Statements
for the six months ended 30 June 2023
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 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.
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 2022. The information for the year ended 31 December 2022
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 2024 (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 cash forecast and scenario analysis is, among other
factors, based on commodity prices per the current forward curve
taking into account downside risks the associated impacts. In
addition, under the RBL the Group has also undertaken commodity
hedging. Sensitivities were created and included, among others, a
reasonably possible low case and high case oil price; and various
hedging scenarios for duration and volumes.
Various risking scenarios, such as medium to long-term oil
prices which could also be potentially impacted by the transition
to a lower carbon economy, costs estimates (including inflation
assumptions) for, and phasing of, operating and capital expenditure
have been considered. In addition, the Group is also potentially
exposed to potential production interruptions such as weather
downtime and planned and unplanned shutdowns for workovers and
repair and maintenance activities.
The Directors have assessed that based on the near-term cash
projections for the going concern period, the Group will have
sufficient cash resources in place throughout the going concern
period, also after taking into consideration of the various risking
scenarios.
Having taken into consideration the above factors, the Directors
have reasonable expectation that the Group will continue in
operational existence for the going concern period. Accordingly,
they adopted the going concern basis in preparing these unaudited
condensed consolidated interim 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 is relevant
to the Group for the first time with effect from 1 January
2023.
- Amendments to IAS 1 Classification of Liabilities as Current
or Non-current - Deferral of Effective
Date
- Amendments to IAS 1 Making Materiality Judgements - Disclosure
of Accounting Policies
And Practice
Statement 2
- Amendments to IAS 8 Definition of Accounting Estimates
- Amendments to IAS 12 Deferred Tax Related to Assets and
Liabilities Arising from a Single
Transaction
The amendments are effective for annual periods beginning on 1
January 2023 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 2022 .
4. OPERATING COSTS
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Restated*
USD'000 USD'000 USD'000
------------------------------- ----------- ----------- --------------
Production costs 87,615 90,115 242,359
Tariffs and transportation
costs 3,035 2,868 8,341
----------- ----------- --------------
Total production costs 90,650 92,983 250,700
=========== =========== ==============
Depletion and amortisation
of oil and
gas properties 17,243 28,681 48,203
Depreciation of plant
equipment and
right-of-use assets 7,331 6,454 13,631
----------- ----------- --------------
Total depletion, depreciation
and
amortisation 24,574 35,135 61,834
=========== =========== ==============
Corporate costs 8,433 5,057 18,325
Other operating expenses 13 446 3,980
----------- ----------- --------------
Total other expenses 8,446 5,503 22,305
=========== =========== ==============
5. FINANCE COSTS
Six months Six months Twelve
ended ended months
ended
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
---------------------- ----------- ----------- ------------
Interest expense and
others 6,553 600 2,780
Accretion expense 9,817 4,184 8,628
Warrants expense 6,147 - -
22,517 4,784 11,408
=========== =========== ============
*Certain H1 2022 comparative information has been restated.
Please refer to Note 25.
6. INCOME TAX EXPENSE
Six months Six months Twelve
ended ended months
30 June 30 June ended
2023 2022 31 December
Unaudited Unaudited 2022
Restated* Audited
USD'000 USD'000
USD'000
--------------------------------- ---------- ---------- ------------
Current tax
Corporate tax charge 29,154 15,656
Overprovision in prior
year (2,176) - 666
---------- ---------- ------------
(2,176) 29,154 16,322
Australian petroleum resource
rent
tax ("PRRT") - (162) (1,121)
Malaysian petroleum income
tax
("PITA") 98 5,928 11,899
(2,078) 34,920 27,100
---------- ---------- ------------
Deferred tax
Corporate tax (8,833) (4,042) 14,149
PRRT (231) 3,244 7,032
PITA 801 4 5,737
========== ========== ============
(8,263) (794) 26,918
---------- ---------- ------------
(10,341) 34,126 54,018
========== ========== ============
*Certain H1 2022 comparative information has been restated.
Please refer to Note 25.
7. (LOSS)/EARNINGS PER ORDINARY SHARE
The calculation of the basic and diluted (loss)/earnings per
share is based on the following data:
Six months Six months Twelve
ended ended months
ended
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Restated*
USD'000 USD'000 USD'000
------------------------- ----------- ----------- ------------
(Loss)/Profit for the
purposes of basic
and diluted per share,
being the net
profit for the period
attributable to
equity holders of the
Company (59,934) 43,545 8,522
=========== =========== ============
Number Number Number
------------------------------ ------------ ------------ ------------
Weighted average number
of ordinary
shares for the purposes
of basic EPS 457,510,000 465,485,869 461,959,228
Effect of dilutive potential
ordinary
shares - share options - 6,029,827 3,876,548
Effect of dilutive potential
ordinary
shares - performance
shares - 595,998 334,163
Effect of dilutive potential
ordinary
shares - restricted
shares - 178,887 202,823
------------ ------------ ------------
Weighted average number
of ordinary
shares for the purposes
of diluted EPS 457,510,000 472,290,581 466,372,762
============ ============ ============
During the current period, 6,427,966 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.
During the current period, 326,477 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.
During the current period, 445,288 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.
During the current period, 3,977,901 of weighted average
contingently issuable shares under the Company's warrants
instrument were excluded from the calculation of diluted EPS, as
they are anti-dilutive in view of the loss for the period.
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2023 2022 2022
(Loss)/Earnings per share Unaudited Unaudited Audited
(US$)
* Basic and diluted (0.13) 0.09 0.02
========== ========== =============
*Certain H1 2022 comparative information has been restated.
Please refer to Note 25.
8. INTANGIBLE EXPLORATION ASSETS
Total
USD'000
----------------------------------------------- ----------
Cost
As at 1 January 2022 93,241
Additions 2,681
Transfer (18,895)*
As at 30 June 2022 77,027
Additions 901
As at 31 December 2022 77,928
Additions 802
----------
As at 30 June 2023 78,730
==========
Impairment
As at 1 January 2022/30 June 2022/31 December -
2022/30 June 2023
==========
Net book value
As at 30 June 2022 (unaudited) 77,027
==========
As at 31 December 2022 (audited) 77,928
==========
As at 30 June 2023 (unaudited) 78,730
==========
* The transfer in 2022 related to the Lemang PSC in Indonesia,
following the final investment decision and award of the
engineering, procurement, construction and installation contract
which established commercial viability. The capitalised cost of
US$18.9 million was transferred to development assets as disclosed
in Note 9.
9. PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties
Production Development Plant Right-of-use
assets assets and equipment assets Total
USD'000 USD'000 USD'000 USD'000 USD'000
------------------- ---- ----------- --- ------------ --- --------------- --- ------------- --- --------
Cost
As at 1 January
2022 595,494 - 12,334 48,368 656,196
Additions 10,687 - 253 1,583 12,523
Reclassification - 18,895 - - 18,895
Written off (3,704) - (67) (5,981) (9,752)
------------
As at 30 June
2022 602,477 18,895 12,520 43,970 677,862
Changes in
asset
restoration
obligations 20,768 7 - - 20,775
Acquisition
of
CWLH Assets 41,976 - - - 41,976
Acquisition
of 10%
interest in
Lemang PSC - 1,414 - - 1,414
Additions 51,632 16,619 103 5,773 74,127
Written off - - (260) - (260)
Transfer - - (1,173) - (1,173)
------------
As at 31 December
2022 716,853 36,935 11,190 49,743 814,721
Additions 1,677 21,026 302 36,827 59,832
Transfer of
50%
interest in
PNLP Assets 48,604* - - - 48,604
Written off - - - (1,584) (1,584)
As at 30 June
2023 767,134 57,961 11,492 84,986 921,573
=========== ============ =============== ============= ========
Accumulated
depletion,
depreciation,
amortisation
and
impairment
As at 1 January
2022 241,902 - 3,371 34,516 279,789
Charge for
the period 32,770 - 307 6,147 39,224
Written off (3,704) - (54) (5,981) (9,739)
------------
As at 30 June
2022 270,968 - 3,624 34,682 309,274
Charge for
the period 12,518 - 309 6,868 19,695
Impairment 13,534 - - - 13,534
Written off - - (61) - (61)
------------
As at 31 December
2022 297,020 - 3,872 41,550 342,442
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 372,424 - 4,163 47,006 423,593
Net book value
As at 30 June
2022
(unaudited) 331,509 18,895 8,896 9,288 368,588
As at 31 December
2022 (audited) 419,833 36,935 7,318 8,193 472,279
As at 30 June
2023
(unaudited) 394,710 57,961 7,329 37,980 497,980
* On 14 April 2023, Jadestone assumed operatorship of the PNLP
Assets following the decision of the previous operator to withdraw.
Accordingly, the Group has assumed the previous operator's share of
decommissioning liabilities following the transfer of operatorship,
with a corresponding increase to the oil and gas properties
balance. The oil and gas properties were impaired as at 30 June
2023 and offset against the non-current other payable (Note 20),
due to the uncertainty in respect to a potential restart date for
production under the PSCs. The Group submitted a Business Value
Proposition ("BVP") on 30 June 2023 for PETRONAS's approval. The
BVP includes an overview of the Group's plan of activities to
reinstate production from the PNLP Assets. If and when approved,
the Group will commence negotiation with PETRONAS on the PSC fiscal
terms and subsequently may seek Jadestone Board's approval prior to
sanctioning the project.
10. INVESTMENT IN ASSOCIATE
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
At beginning of period/year - - -
Acquisition of 9.52% non-operated
interest in
Sinphuhorm Assets 27,853 - -
At end of period/year 27,853 - -
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 northeast Thailand. The
acquisition was completed on 23 February 2023, for a cash
consideration of US$27.9 million post customary closing
adjustments. The effective date of the transaction was 1 January
2022.
11. TRADE AND OTHER RECEIVABLES
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Restated*
USD'000 USD'000 USD'000
Current
Trade receivables 6,388 535 6,332
Prepayments 7,064 7,166 3,119
Other receivables and deposits 51,678 2,175 4,859
Amount due from joint arrangement
partners (net) 2,589 226 4,268
Underlift crude oil inventories 4,251 1,847 107
PRRT receivables - 162 -
VAT receivables 1,079 1,522 1,683
73,049 13,633 20,368
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Restated*
USD'000 USD'000 USD'000
Non-current
Other receivables 181,798 41,895 83,192
VAT receivables 9,329 4,922 7,398
191,127 46,817 90,590
264,176 60,450 110,958
The current other receivables as at 30 June 2023 mainly relates
to a joint arrangement partner's share of future decommissioning
costs when it exited two PSCs' licences during H1 2023.
The increase of non-current other receivables during the period
represents additional payments of US$41.0 million into the CWLH
abandonment trust fund. Additionally, the total accumulated cess
payment paid to the Malaysian regulator of US$56.4 million for the
PNLP Assets is now presented on a gross basis, as opposed to
offsetting against the provision for asset retirement obligations,
following the transfer of operatorship of the PSCs in April 2023.
In 2022, this asset retirement obligation was presented on a net
basis to reflect the PSCs were non-operated, in line with the
Group's accounting policies. The asset retirement liability
associated with the PSCs is now presented on a 100% gross position
in the Group's balance sheet (Note 17).
12. CASH AND BANK BALANCES
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Reclassified*
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 1,000 621 676
Current 117,782 161,007 122,653
118,782 161,628 123,329
The non-current cash and cash equivalents represents the
restricted cash balance of US$0.7 million (H1 2022: US$0.3 million)
and US$0.3 million (H1 2022: US$0.3 million) in relation to a
deposit placed for bank guarantee with respect to the PenMal Assets
and Australian office building, respectively. The bank guarantees
are expected to be in place for a period of more than twelve
months. Accordingly, reclassification was made to H1 2022
comparatives to classify the amount as a non-current asset as
disclosed in Note 25, as a result of the April 2022 IFRIC Agenda
item "Demand Deposits with Restrictions on Use arising from a
Contract with a Third Party (IAS 7 Statement of Cash Flows).
*Certain H1 2022 comparative information has been restated and
reclassified between line items. Please refer to Note 25.
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 H1 2023
and it is classified as a current asset.
13. SHARE CAPITAL AND SHARE PREMIUM ACCOUNT
Share Share premium
capital account
No. of USD'000 USD'000
shares
Issued and fully paid
As at 1 January 2022 465,081,238 358 201
Issued during the period 972,378 1 669
As at 30 June 2022 (Restated)* 466,053,616 359 870
Issued during the period 473,730 1 113
Share repurchases (18,173,683) (21) -
As at 31 December 2022 448,353,663 339 983
Issued during the period 94,283,543 120 50,844
Vesting of 2020 performance 79,327 - -
shares
Vesting of 2020 restricted 101,063 - -
shares
Share repurchased (2,051,022) (3) -
As at 30 June 2023 540,766,574 456 51,827
=============
On 19 January 2023, the Company suspended its share buyback
programme. For the period ended 30 June 2023, the Company had
acquired 2.1 million shares at a weighted average cost of GBP0.75
per share, resulting in total expenditure of US$1.8 million. The
total nominal value of the shares repurchased was US$2,485. All
shares repurchased were cancelled.
On 6 June 2023, the Company completed an equity fundraising,
creating an additional 94,081,826 ordinary shares at GBP0.45 per
share , which comprised of a placing and subscription of 92,312,691
new ordinary shares to existing and new institutional shareholders
and a placing and subscription of 1,769,135 new ordinary shares to
the Directors of the Company. Total gross proceeds were US$53.1
million, with net proceeds of US$51.1 million.
On 9 June 2023, the Company launched an open offer of up to
14,887,039 new ordinary shares, at GBP0.45 per share , to raise
additional proceeds of up to EUR8.0 million (up to US$8.6 million).
The open offer closed on 28 June 2023, raising a total of US$42,009
by issuing 73,557 new shares.
The Company has one class of ordinary share. Fully paid ordinary
shares with par value of GBP0.001 per share carry one vote per
share without restriction, and carry a right to dividends as and
when declared by the Company.
*Certain H1 2022 comparative information has been restated.
Please refer to Note 25.
14. 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.
15. 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 .
16. HEDGING RESERVE
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
------------------------------------
At beginning of the period/year - - -
Loss arising on changes in
fair value of hedging
instruments during the period/year 10,985 - -
Income tax related to loss
recognised in other
comprehensive income (2,160) - -
Net loss reclassified to profit
or loss - - -
Income tax related to amounts
reclassified to
profit or loss - - -
At end of the period/year 8,825 - -
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.
17. PROVISIONS
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Non-current
Asset restoration obligations 570,755 408,585 493,985
Others 8,464 4,866 14,554
579,219 413,451 508,539
Current
Asset restoration obligations 9,551 - -
Others 7,390 3,503 703
16,941 3,503 703
574,656 416,954 509,242
The increase in the provision for asset restoration obligations
by US$86.3 million during the period represents the additional
decommissioning obligations of US$48.6 million following the
transfer of operatorship of the PNLP Assets in April 2023.
Additionally, US$28.2 million of asset retirement obligation
associated with the PNLP Assets , net to Jadestone's 50% interest
prior to transfer of operatorship, is now presented on a gross
basis, with the Group is now being the operator of the PSCs. The
cess payment paid to cover for this amount is now presented as a
non-current other receivable in Note 11, in line with the Group's
accounting policies. The Group also incurred accretion expense of
US$9.6 million during the period.
18. BORROWINGS
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Non-current secured borrowings
Reserve based lending facility 82,194 - -
Current secured borrowings
Reserve based lending facility 22,802 - -
104,996 - -
On 17 February 2023, the Group closed a US$50.0 million Interim
Facility with two international banks to provide additional
liquidity prior to closing the RBL facility. US$28.5 million of the
Interim Facility was drawn in February 2023 to fund the acquisition
of the Sinphuhorm Assets. The second drawdown of US$21.5 million
occurred in May 2023 primarily to fund the US$20.5 million payment
into the CWLH abandonment trust fund. The Interim Facility was
repaid on 1 June 2023 from the RBL facility obtained by the Group
in May 2023. The Group had incurred interest expense of US$1.3
million from the Interim Facility, which was recorded as finance
costs in Note 5.
On 19 May 2023, the Group signed a US$200.0 million RBL facility
with a group of four international banks ("the RBL Banks"). The
facility tenor is four years, with the final maturity date being
the earlier of 31 March 2027 and the projected reserves tail(1)
(which is expected later). The borrowing base is 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. The borrowing base as at 30
June 2023 was US$200.0 million.
The RBL facility pays interest at 450 basis points over the
secured overnight financing rate, plus the applicable credit
spread. The Group also pays customary arrangement and commitment
fees.
The first drawdown of the RBL facility of US$111.0 million
occurred on 1 June 2023. The loan incurred costs of US$6.9 million
and the fair value of the loan at drawdown had an amortised
carrying value of US$104.1 million. For the period ended 30 June
2023, the Group had incurred interest expense of US$0.9 million and
US$0.3 million of commitment fees, which were recorded as finance
costs in Note 5.
On 6 June 2023, the Company entered into a committed standby
working capital facility with Tyrus for a facility size of up to
US$35.0 million. The standby working capital facility was finalised
at US$31.9 million, after deduction of US$3.1 million of excess
funds from the total gross funds of US$53.1 million raised from the
equity placing and open offer. The facility will mature with a
bullet repayment on 31 December 2024. The facility bears interest
of 15% on drawn amounts and 5% on undrawn amounts and can be repaid
or cancelled without penalties. The standby working capital
facility was undrawn as at 30 June 2023.
(1) Reserves tail date refers to the last day of the quarter
immediately preceding the quarter in which the remaining borrowing
base reserves are forecast to be 25 per cent (or less) of the
initial approved borrowing base reserves.
19. TRADE AND OTHER PAYABLES
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Current
Trade payables 24,539 5,602 13,606
Other payables 15,506 4,862 8,643
Accruals 32,215 33,267 36,757
Contingent payments - - 5,000
Malaysian supplementary payment
payables 732 2,839 855
Amount due to joint arrangement
partner 433 - 1,269
Overlift crude oil inventories - - 7,357
GST/VAT payables 327 5 265
73,752 46,575 73,752
Non-current
Other payable 29,014 - -
102,766 46,575 73,752
Non-current other payable represents future activities which are
operational in nature for which cash advances are to be received
from a joint arrangement partner for its share of future
decommissioning costs when it exited two PSCs' licences during H1
2023.
20. 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.
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
--------------------------------- ---------- -----------
Derivative financial liabilities
Designated as cash flow hedges
Commodity capped swap 10,985 - -
========== ===========
Analysed as:
Current 4,599 - -
Non-current 6,386 - -
10,985 - -
========== ===========
The following is a summary of the Group's outstanding derivative
contracts:
Fair value
Fair value Fair value asset at
asset at asset at 31 December
30 June 2023 30 June 2022 2022
Contract Type of Contract Hedge Unaudited Unaudited Audited
quantity contracts Terms price classification USD'000 USD'000 USD'000
Contracts designated as cash flow hedges
50% of
Group's Commodity Oct Weighted
planned capped 2023 - average price
2PD swap: swap Sep of
production component 2025 US$70.29/bbl Cash flow 10,985 - -
21. 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.à.r.l ("Tyrus") for 30
million ordinary shares at an exercise price of 50 pence per share.
The warrants are exercisable within 36 months from the date of
issuance, with an expiry date of 5 June 2026. Management has
applied the Black-Scholes option-pricing model to estimate the fair
value of the warrants.
22. 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 2023 (unaudited)
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
costs (7,066) (3,169) (974) (4,329) (15,538)
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 tax (42,053) (3,720) (3,148) (21,354) (70,275)
Additions to non-
current assets 79,647 84,731 24,145 500 189,023
Non-current assets 429,091 200,042 139,126 28,431 796,690
Six months ended 30 June 2022 (unaudited) (Restated)*
Revenue
Liquids revenue 175,476 48,256 - - 223,732
Hedging income - 1,907 - - 1,907
175,476 50,163 - - 225,639
Production costs (58,792) (34,191) - - (92,983)
DD&A (33,065) (1,771) (117) (182) (35,135)
Administrative staff
costs (7,239) (2,023) (1,189) (4,714) (15,165)
Other expenses (2,225) (619) (663) (1,996) (5,503)
Other income 3,281 54 14 349 3,698
Finance costs (3,397) (1,173) (200) (14) (4,784)
Other financial gains 1,904 - - - 1,904
Profit/(Loss) before
tax 75,943 10,440 (2,155) (6,557) 77,671
Additions to non-
current assets 12,303 322 2,829 67 15,521
Non-current assets 340,355 58,444 93,650 604 493,053
*Certain H1 2022 comparative information has been restated.
Please refer to Note 25.
Producing Exploration/
assets development
Australia SEA SEA Corporate Total
USD'000 USD'000 USD'000 USD'000 USD'000
Twelve months ended 31 December 2022 (audited)
Revenue
Liquids revenue 328,863 89,620 - - 418,483
Gas revenue - 3,119 - - 3,119
328,863 92,739 - - 421,602
Production cost (189,041) (61,659) - - (250,700)
DD&A (57,835) (3,405) (235) (359) (61,834)
Administrative staff
costs (13,839) (4,073) (2,020) (9,286) (29,218)
Other expenses (8,872) (1,877) (8,188) (3,368) (22,305)
Impairment - (13,534) - - (13,534)
Other income 24,226 2,718 965 124 28,033
Finance costs (6,698) (2,033) (903) (1,774) (11,408)
Other financial gains 1,904 - - - 1,904
Profit/(Loss) before tax 78,708 8,876 (10,381) (14,663) 62,540
Additions to non-
current assets 110,405 582 23,266 69 134,322
Non-current assets 424,017 101,835 115,390 231 641,473
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.
23. EVENTS AFTER THE REPORTING PERIOD
Montara operations update
On 29 July 2023, production at Montara was temporarily shut in
following a hydrocarbon gas alarm in ballast water tank 4S.
Inspections identified the location of a small defect between tank
4S and oil cargo tank 5C, with repairs currently in progress.
Ballast water tank 4P was returned to service in early September
2023 following minor repairs. Production restarted on 1 September
2023.
24. RELATED PARTY TRANSACTIONS
Placement of additional shares
On 7 June 2023, the Company completed an equity fundraising,
creating an additional 94,081,826 ordinary shares at GBP0.45 per
share , of which a placing and subscription of 1,769,135 new
ordinary shares were acquired by the Directors of the Company for a
total consideration of US$0.7 million.
25. RESTATEMENT AND RECLASSIFICATION OF COMPARATIVE FIGURES
Certain comparative figures in the consolidated financial
statements 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 restatement made was in relation to the change
in accounting policy on the measurement of under/overlift, from
recorded at the prevailing market price to recorded at the lower of
cost and net realisable value as disclosed in Note 2.
The reclassifications made in the consolidated statement of
financial position are related to the restricted cash held by the
Group in relation to deposits placed for bank guarantees with
respect to the PenMal Assets and Australian office buildings as a
result of the April 2022 IFRIC Agenda item "Demand Deposits with
Restrictions on Use arising from a Contract with a Third Party (IAS
7 Statement of Cash Flows). Additionally, the Group reclassed the
fair value proceeds received from the issuance of shares to share
premium account. The reclassifications do not impact the
consolidated statement or profit or loss and other comprehensive
income and consolidated statement of cash flows.
The reclassifications made in the consolidated statement of cash
flows are related to the placement of decommissioning trust fund
for the CWLH Assets, placement of abandonment cess fund for the
PenMal Assets and interest paid, which are now classified in
accordance to the nature of activities. The reclassifications do
not impact the consolidated statement or profit or loss and other
comprehensive income and consolidated statement of financial
position.
The restatements and reclassifications impact the following
items:
Restatements As restated
As previously and and reclassified
reported reclassifications USD'000
USD'000 USD'000
Consolidated statement of profit
or loss and other
comprehensive income for the
period ended
30 June 2022
Production costs (83,401) (9,582) (92,983)
Other income 5,602 (1,904) 3,698
Other financial gains - 1,904 1,904
Income tax expense (37,767) 3,641 (34,126)
Consolidated statement of financial
position as at
30 June 2022
Deferred tax assets 14,366 5,683 20,049
Trade and other receivables 28,588 (14,955) 13,633
Cash and cash equivalents -
non-current - 621 621
Cash and cash equivalents -
current 161,628 (621) 161,007
Share capital 1,229 (870) 359
Share premium account - 870 870
Retained earnings 11,553 (9,272) 2,281
Consolidated statement of cash
flows for the
period ended 30 June 2022
Profit before tax 87,253 (9,582) 77,671
Increase in trade and other
receivables 10,505 9,751 20,256
Interest paid - operating activities (600) 600 -
Placement of abandonment cess
fund for PenMal
Assets - (169) (169)
Interest paid - financing activities - (200) (200)
Interest on lease liabilities
paid - financing activities - (400) (400)
Consolidated statement of cash
flows for the
year ended 31 December 2022
(Increase)/Decrease in trade
and other receivables (214) 41,397 41,183
Placement of decommissioning
trust fund for
CWLH Assets - (41,000) (41,000)
Placement of abandonment cess
fund for
PenMal Assets - (397) (397)
Glossary
GBP 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.
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
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END
IR NKCBQPBKKACD
(END) Dow Jones Newswires
September 19, 2023 02:00 ET (06:00 GMT)
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