REG - Jadestone Energy PLC - 2023 Half Year Results
19/09/2023 07:00
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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 1.41 2.03 1.63
(US$/mscf)
Revenue 86,660 225,639 421,602
Production costs (restated(3)) (90,650) (92,983) (250,700)
Adjusted unit operating costs per barrel of oil equivalent 40.27 25.71 37.49
(US$/boe)(4)
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$) (0.13) 0.09 0.02
(restated(3))
Operating cash flows before movement in working capital (24,179) 116,899 158,148
(restated(3))
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
£0.45 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 £0.50 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 (mailto:ir@jadestone-energy.com)
Stifel Nicolaus Europe Limited (Nomad, Joint Broker) +44 (0) 20 7710 7600 (UK)
Callum Stewart / Jason Grossman / Ashton Clanfield
Jefferies International Limited (Joint Broker) +44 (0) 20 7029 8000 (UK)
Tony White / Will Soutar
Camarco (Public Relations Advisor) +44 (0) 203 757 4980 (UK)
Billy Clegg / Andrew Turner / Elfie Kent jadestone@camarco.co.uk (mailto:jadestone@camarco.co.uk)
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
(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
(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. On 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/
(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.
USD'000 except where indicated Six Six Twelve months ended
months ended months ended 31 December 2022
30 June 30 June
2023 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 1.41 2.03 1.63
(US$/mscf)
Revenue 86,660 225,639 421,602
Production costs (restated(3)) (90,650) (92,983) (250,700)
Adjusted unit operating costs per barrel of oil equivalent, 40.27 25.71 37.49
(US$/boe)(4)
Adjusted EBITDAX(4) (restated(3)) (3,127) 130,930 161,929
Unit depletion, depreciation & amortisation (US$/boe) 13.15 12.06 10.80
Impairment of assets - - (13,534)
(Loss)/Profit before tax (restated(3)) (70,275) 77,671 62,540
(Loss)/Profit after tax (restated(3)) (59,934) 43,545 8,522
(Loss)/Earnings per ordinary share: basic and diluted (US$) (0.13) 0.09 0.02
(restated(3))
Operating cash flows before movement in working capital (24,179) 116,899 158,148
(restated(3))
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 123,329 117,865
period
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 (24,179) 116,899
working capital
Movements in working capital (restated(1)) (30,377) (12,907)
Net tax paid (4,755) (34,177)
Purchases of intangible exploration assets, oil and (23,439) (13,364)
gas properties, and plant and equipment(2)
Cash paid for acquisition of Sinphuhorm Assets (27,853) -
Placement of decommissioning trust fund for (41,000) -
CWLH Assets
Placement of abandonment cess fund for PenMal - (169)
Assets
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 118,782 161,628
period
NON-IFRS MEASURES
The Group uses certain performance measures that are not specifically defined
under IFRS, or other generally accepted accounting principles. These
non-IFRS measures comprise adjusted unit operating cost per barrel of oil
equivalent (adjusted opex/boe), adjusted EBITDAX, outstanding debt, and net
cash.
The following notes describe why the Group has selected these non-IFRS
measures.
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 ended Six months ended Twelve months ended
30 June 30 June 31 December 2022
USD'000 except where indicated 2023 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 24,897 8,830 (39,436)
movement(3) (restated(1))
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 (7,298) (16,731) (26,381)
Australian royalties(8)
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 40.27 25.71 37.49
equivalent
(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 ended Six months ended Twelve months ended
30 June 30 June 31 December 2022
2023 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 - - 7,333
payments
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 2022
USD'000 2023 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 months ended 31 December 2022
ended ended
30 June 30 June
2023 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 flow hedges (10,985) - -
Hedging gain reclassified to profit or loss - - -
(10,985) - -
Tax credit relating to components of other 2,160 - -
comprehensive loss
Other comprehensive loss (8,825) - -
Total comprehensive (loss)/income for the (68,759) 43,545 8,522
period/year
*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 2022
2023 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 2022
2023 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 - - - - - - 43,545 43,545
total comprehensive income for
the period
Dividend paid - - - - - - (6,241) (6,241)
Share-based payments - - - 683 - - - 683
Shares issued (Note 13) 1 669 - - - - - 670
Total transactions with owners, 1 669 - 683 - - (6,241) (4,888)
recognised directly in equity
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 - - - - - - 8,522 8,522
total comprehensive income for
the year
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, (19) 782 - 971 21 - (25,286) (23,531)
recognised directly in equity
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 - - - - - - (59,934) (59,934)
total comprehensive income for
the period
Other comprehensive loss for the - - - - - (8,825) - (8,825)
period
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, 117 50,468 - 458 3 - (2,084) 49,338
recognised directly in equity
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
ended ended months 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 and amortisation 4 / 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 - - (1,904)
repayment plan
Reversal of impairment of amount due from - - (912)
joint arrangement partner
Operating cash flows before movements in (24,179) 116,899 158,148
working capital
(Increase)/Decrease in trade and other (36,158) 20,256 41,183
receivables
Increase in inventories (18,630) (10,774) (1,096)
Increase/(Decrease) in trade and other 24,411 (22,389) (2,471)
payables
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 (59,311) 69,646 162,634
activities
*Certain H1 2022 comparative information has been restated. Please refer to
Note 25.
Six months Six months Twelve
ended ended months 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 10 (27,853) - -
Assets
Cash received from acquisition of CWLH - - 5,750
Assets
Cash paid for acquisition of 10% interest of - - (500)
Lemang PSC
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 (41,000) - (41,000)
CWLH Assets
Placement of abandonment cess fund for - (169) (397)
PenMal Assets
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 145,590 (12,689) (39,276)
activities
Net (decrease)/increase in cash and cash (4,547) 43,763 5,464
equivalents
Cash and cash equivalents at beginning of the 123,329 117,865 117,865
period/year
Cash and cash equivalents at end of the 118,782 161,628 123,329
period/year
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 ended Six months ended Twelve 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 17,243 28,681 48,203
gas properties
Depreciation of plant equipment and 7,331 6,454 13,631
right-of-use assets
Total depletion, depreciation and 24,574 35,135 61,834
amortisation
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 ended Six months ended Twelve
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 ended
30 June 30 June 31 December
2023 2022 2022
Unaudited Unaudited Audited
Restated*
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 - (162) (1,121)
tax ("PRRT")
Malaysian petroleum income tax 98 5,928 11,899
("PITA")
(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 ended Six months ended Twelve
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 (59,934) 43,545 8,522
and diluted per share, being the net
profit for the period attributable to
equity holders of the Company
Number Number Number
Weighted average number of ordinary 457,510,000 465,485,869 461,959,228
shares for the purposes of basic EPS
Effect of dilutive potential ordinary - 6,029,827 3,876,548
shares - share options
Effect of dilutive potential ordinary - 595,998 334,163
shares - performance shares
Effect of dilutive potential ordinary - 178,887 202,823
shares - restricted shares
Weighted average number of ordinary 457,510,000 472,290,581 466,372,762
shares for the purposes of diluted EPS
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 ended Six months ended Twelve
months ended
30 June 30 June 31 December
2023 2022 2022
(Loss)/Earnings per share (US$) Unaudited Unaudited Audited
- - 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 Plant and equipment Right-of-use assets
Total
Production assets Development assets
USD'000 USD'000 USD'000 USD'000 USD'000
Cost
As at 1 January 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 20,768 7 - - 20,775
restoration obligations
Acquisition of 41,976 - - - 41,976
CWLH Assets
Acquisition of 10% - 1,414 - - 1,414
interest in Lemang PSC
Additions 51,632 16,619 103 5,773 74,127
Written off - - (260) - (260)
Transfer - - (1,173) - (1,173)
As at 31 December 716,853 36,935 11,190 49,743 814,721
2022
Additions 1,677 21,026 302 36,827 59,832
Transfer of 50% 48,604* - - - 48,604
interest in PNLP Assets
Written off - - - (1,584) (1,584)
As at 30 June 2023 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 297,020 - 3,872 41,550 342,442
2022
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 331,509 18,895 8,896 9,288 368,588
(unaudited)
As at 31 December 419,833 36,935 7,318 8,193 472,279
2022 (audited)
As at 30 June 2023 394,710 57,961 7,329 37,980 497,980
(unaudited)
* 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 27,853 - -
Sinphuhorm Assets
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 2022
2023 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 2,589 226 4,268
partners (net)
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 2022
2023 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 2022
2023 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 account
capital
No. of shares USD'000 USD'000
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 shares 79,327 - -
Vesting of 2020 restricted shares 101,063 - -
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 £0.75 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 £0.45 per share, which comprised of
a placing and subscription of 92,312,691 new ordinary shares to existing and
new institutional shareholders and a placing and subscription of 1,769,135 new
ordinary shares to the Directors of the Company. Total gross proceeds were
US$53.1 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 £0.45 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 £0.001 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 10,985 - -
instruments during the period/year
Income tax related to loss recognised in other (2,160) - -
comprehensive income
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 2022
2023 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 2022
2023 2022 Audited
Unaudited Unaudited 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 asset at Fair value asset at Fair value asset at
30 June 2023 30 June 2022 31 December
Unaudited Unaudited 2022
Contract quantity Type of contracts Hedge classification USD'000 USD'000 Audited
Terms Contract price USD'000
Contracts designated as cash flow hedges
50% of Commodity Oct Weighted Cash flow 10,985 - -
Group's capped 2023 - average price
planned swap: swap Sep of
2PD component 2025 US$70.29/bbl
production
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 (7,066) (3,169) (974) (4,329) (15,538)
costs
Other expenses (2,103) (1,111) (778) (4,454) (8,446)
Other income 4,299 56 - 435 4,790
Finance costs (6,856) (1,523) (1,283) (12,855) (22,517)
Loss before tax (42,053) (3,720) (3,148) (21,354) (70,275)
Additions to non- 79,647 84,731 24,145 500 189,023
current assets
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 (7,239) (2,023) (1,189) (4,714) (15,165)
costs
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 75,943 10,440 (2,155) (6,557) 77,671
tax
Additions to non- 12,303 322 2,829 67 15,521
current assets
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 (13,839) (4,073) (2,020) (9,286) (29,218)
costs
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- 110,405 582 23,266 69 134,322
current assets
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 £0.45 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 and As restated and reclassified
As previously 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 - (169) (169)
Assets
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 - (41,000) (41,000)
CWLH Assets
Placement of abandonment cess fund for - (397) (397)
PenMal Assets
Glossary
£ British pound sterling
2P the sum of proved and probable reserves, reflecting those reserves with 50%
probability of quantities actually recovered being equal or greater to the sum
of estimated proved plus probable reserves
AAKBNLP Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields
AIM Alternative Investment Market
ARO Asset retirement obligations
API American Petroleum Institute gravity
bbl barrel
bbls/d barrels per day
boe barrels of oil equivalent
boe/d barrels of oil equivalent per day
DD&A depletion, depreciation and amortisation
EBITDAX earnings before interest tax, depreciation, amortisation and exploration
FPSO floating production storage and offloading
GHG greenhouse gases
IFRS International Financial Reporting Standards
LPG Liquefied petroleum gas
mcf thousand cubic feet of natural gas
mm million
mmbbls million barrels
mmboe million barrels of oil equivalent
NOPSEMA National Offshore Petroleum Safety and Environmental Management Authority
opex operating expenditures
PETRONAS Petroliam Nasional Berhad
PITA Petroleum Income Tax
PRRT Petroleum Resource Rent Tax
PSC production sharing contract
RBL reserves based loan
reserves hydrocarbon resource that is anticipated to be commercially recovered from
known accumulations from a given date forward
US$ or USD United States dollar
The technical information contained in this announcement has been prepared in
accordance with the June 2018 guidelines endorsed by the Society of Petroleum
Engineers, World Petroleum Congress, American Association of Petroleum
Geologists and Society of Petroleum Evaluation Engineers Petroleum Resource
Management System.
A. Shahbaz Sikandar of Jadestone Energy plc, Group Subsurface Manager with a
Masters degree in Petroleum Engineering, and who is a member of the Society of
Petroleum Engineers and has worked in the energy industry for more than 25
years, has read and approved the technical disclosure in this regulatory
announcement.
The information contained within this announcement is considered to be inside
information prior to its release, as defined in Article 7 of the Market Abuse
Regulation No. 596/2014 which is part of UK law by virtue of the European
Union (Withdrawal) Act 2018, and is disclosed in accordance with the Company's
obligations under Article 17 of those Regulations.
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