2023 Full Year
Results
29 April 2024-Singapore: Jadestone Energy plc (AIM:JSE) ("Jadestone" or the
"Company"), an independent upstream company and its subsidiaries
(the "Group"), focused on the Asia-Pacific region, reports its
consolidated financial statements (the "Financial Statements"), as
at and for the financial year ended 31 December 2023.
The Company will host a webcast at
9:00 a.m. UK time today, details of which can be found in the
announcement below.
Key updates:
l Proven
and Probable ("2P") reserves at 31 December 2023 of 68.0 mmboe (31
December 2022: 64.8 mmboe), representing 164% 2P reserves
replacement during the year. 2C contingent resources increased
slightly to 105.6 mmboe (31 December 2022: 104.3 mmboe).
l Commercial gas sales from the Akatara gas field expected to
commence before the end of the second quarter of 2024, consistent
with previous guidance.
l March
2024 reserve-based lending ("RBL") facility redetermination has set
a borrowing base of US$200.0 million for the six- month period
ending 30 September 2024.
l The
2024 production guidance range is narrowed from 20-23,000 boe/d to
20-22,000 boe/d. The change to the upper end of guidance reflects
first quarter Group production performance, which was impacted by
both planned and unplanned downtime across the portfolio. Current
internal forecasts point to an outcome at the lower end of the
updated guidance range, based on first commercial gas sales from
Akatara in June 2024, albeit there remains a wide range of possible
outcomes, principally based on the timing and nature of Akatara's
ramp up, as well as initiatives underway to optimise production at
the Group's current producing assets.
l 2024
operating cost guidance is unchanged at US$240.0-290.0 million
(excluding forecast royalties and carbon taxes totalling c.US$30.0
million).
l 2024
capital expenditure guidance is unchanged at US$80.0 - 110.0
million.
l US$91.3
million loss after tax for 2023 (2022: US$9.2 million profit),
principally driven by lower oil prices year-on-year, downtime at
Montara for FPSO tank repairs, asset impairments and higher finance
costs.
l Net
debt of US$78.2 million at 31 March 2024 (31 December 2023: US$3.6
million) reflects c.US$121.8 million of consolidated Group cash
balances and US$200.0 million of debt drawn under the Group's RBL
facility. The end March 2024 net debt figure excludes an
estimated US$110.5 million of proceeds for March 2024 liftings
which were received in April 2024.
Paul Blakeley, President and CEO commented:
"2023 was a pivotal year for Jadestone, as we continued the
deliberate move away from our older legacy assets in Australia
towards newer and higher-value, higher-margin assets across the
Asia-Pacific region. During the year we achieved a number of
operational and strategic milestones, including significant
progress toward first gas at Akatara, a very successful infill
drilling campaign offshore Malaysia and 164% replacement of 2P
reserves. Closing the Sinphuhorm acquisition and doubling our
interest in the CWLH fields offshore Australia were also key steps
in the ongoing diversification strategy. Commercial progress on Nam
Du/U Minh in early 2024 provides greater confidence in our
medium-term outlook. We also delivered a strong HSE performance
during the year, with no lost time injuries, and bolstered our
pledge to deliver Net Zero Scope 1 and 2 GHGs from our operated
assets by 2040 through establishing interim GHG reduction
milestones.
While these positive developments were somewhat overshadowed
by a disappointing performance at Montara in the first half of
2023, we have since seen steady progress in the asset's reliability
as the ongoing work to the FPSO has helped support improving
uptime.
Partly as a result of the challenges at Montara and lower
realised oil prices the business made a loss of US$91 million in
2023 (2022: US$9 million profit). With stronger oil prices so far
this year and our production growing, we expect 2024 to deliver a
much better outcome, with the recent March 2024 RBL redetermination
setting a borrowing base of US$200 million for the next two
quarters, more than double the predicted lending capacity for this
period only a year ago and underpinning near-term liquidity.
Akatara cashflows and the recent increase in our CWLH stake will
further diversify and increase the robustness of our cash
generation.
In recent months, the construction activity at the Akatara
gas processing facility ("AGPF") has been coming to a conclusion in
preparation for first gas. The sales gas pipeline has been
completed and successfully tested, with four out of the five
planned production wells successfully worked over and the first
three tested at a combined rate in excess of 30 mmcfd, well above
the 25 mmcfd required to meet deliveries under the gas sales
agreement. We currently anticipate that commissioning gas
will be introduced into the AGPF followed by commercial gas sales
before the end of the second quarter, consistent with our
long-standing guidance. There is still significant activity
to complete, but we are on the threshold of a significant milestone
for Jadestone.
Average production for the Group in the first quarter of 2024
was 17,200 boe/d, which primarily reflects the impact on our
Australian assets of a very active cyclone season at the start of
this year. Accordingly, production guidance for 2024 has been
narrowed to 20-22,000 boe/d. Both the 2024 opex and capex guidance
ranges are reiterated today.
While the sale process for Woodside's interests in the
Pyrenees/Macedon fields did not proceed, bringing the related share
trading suspension to an end, we had provided a competitive and
fully funded proposal without any recourse to equity. The learnings
from this process provide us with the financial framework to
continue assessing the exciting set of inorganic opportunities
across the Asia-Pacific region, through which we are well placed to
create value from our operating platform and capability. Finally, I
would like to take this opportunity to thank my colleagues at
Jadestone for their hard work in 2023, and our shareholders for
their patience and continued support."
Paul Blakeley
EXECUTIVE DIRECTOR, PRESIDENT AND
CHIEF EXECUTIVE OFFICER
2023 SUMMARY
USD'000 except where
indicated
|
2023
|
2022
Restated*
|
|
|
|
Sales volume, barrels of oil
equivalent (boe)
|
3,862,741
|
4,326,770
|
Production,
boe/day1
|
13,813
|
11,487
|
Realised oil price per barrel of
oil equivalent (US$/boe)2
|
87.34
|
103.85
|
Realised gas price per
thousand standard cubic feet (US$/mscf)
|
1.53
|
1.63
|
Revenue3
|
309,200
|
421,602
|
Production costs
|
(232,772)
|
(250,300)
|
Adjusted unit operating costs per
barrel of oil equivalent (US$/boe)4
|
37.24
|
37.49
|
Adjusted
EBITDAX4
|
90,647
|
162,329
|
(Loss)/Profit after tax
|
(91,274)
|
9,237
|
(Loss)/Earnings per ordinary
share: basic & diluted (US$)
|
(0.18)
|
0.02
|
Operating cash flows before
movement in working capital
|
36,499
|
158,548
|
Capital expenditure
|
115,882
|
82,876
|
Net
(debt)/cash4
|
(3,596)
|
123,329
|
Operational and financial summary
·
2P reserves at year-end 2023 totalled 68.0 mmboe,
a 5% increase on year-end 2022 (64.8 mmboe), mainly due to the
acquisition of the Sinphuhorm Assets and increases at the CWLH
Assets, PenMal Assets and Lemang PSC, partly offset by a reduction
at Montara, and representing a 2P reserves replacement of
164%;
·
2023 production increased by 20% year-on-year to
an annual record of 13,813 boe/d (2022: 11,487 boe/d), primarily
attributable to a full-year of production from the CWLH Assets in
2023 compared to two months in 2022, and the contribution of the
Sinphuhorm Assets from closing of the acquisition in February 2023.
This increase was partly offset by lower production at Montara due
to the impact of FPSO tank repairs;
·
Total lifted volumes in 2023 reduced by 11% to
3.9 mmboe compared to 4.3 mmboe in 2022, mainly reflecting lower
production at Montara;
·
Total revenue decreased by 27% to US$309.2
million (2022: US$421.6 million) due to a 16% decrease year-on-year
in realised prices, combined with lower lifted volumes. Total 2023
revenue includes a hedging loss of US$10.3 million from commodity
swap contracts entered into in support of the reserves-based
lending ("RBL") facility;
·
The average realised oil price for the year
before hedging was US$87.34/bbl in 2023 (2022: US$103.85/bbl). The
average realised price premium was US$5.58/bbl for 2023 (2022:
US$7.81/bbl);
·
Production costs totalled US$232.8 million in
2023, a 7% decrease from US$250.3 million in 2022. This decrease
was primarily driven by a credit for inventory changes and lower
supplementary payments in Malaysia, which more than offset a full
year of operating costs at the CWLH Assets and higher tanker cost
and fuel charges at Stag and Montara;
¡ 2023 adjusted unit operating costs3 of
US$37.24/boe were unchanged year-on-year (2022:
US$37.49/boe);
·
2023 adjusted EBITDAX decreased by 44% to US$90.6
million, compared to US$162.3 million in 2022, primarily due to the
revenue effects detailed above;
·
2023 net loss after tax of US$91.3 million (2022:
US$9.2 million profit after tax);
·
2023 operating cash flow before movements in
working capital of US$36.5 million, a decrease of 77% compared to
2022 (US$158.5 million);
·
2023 capital expenditure of US$115.9 million was
40% higher year-on-year (2022: US$82.9 million), primarily due to
the ramp up of activities at the Akatara development project
onshore Indonesia;
·
Closed c.US$282.0 million of debt facilities and
raised US$51.0 million equity capital during the year:
¡ A
US$50.0 million Interim Facility was closed in February 2023 and
partly used for the acquisition of the Sinphuhorm Assets, with the
Interim Facility fully repaid upon closing of the RBL
facility;
¡ A
US$200.0 million RBL facility was closed in May 2023, supporting
the Group's strategy and investment program;
¡ A
placing and open offer in June 2023 raised c.US$51.0 million, net
of costs; and
¡ A
US$31.9 million standby working capital facility was closed in June
2023, providing additional liquidity in support of the Group's
investment plans. The standby working capital facility expires on
31 December 2024.
·
Net debt of US$3.6 million at 2023 year-end (2022
year-end: net cash of US$123.3 million), reflecting a drawdown of
US$157.0 million from the RBL facility and total cash and cash
equivalents of US$153.4 million. The US$31.9 million working
capital facility remained undrawn following closing in June
2023.
¡ The RBL facility debt capacity upon closing in May 2023 was
US$200.0 million. The September 2023 redetermination confirmed a
debt capacity of US$200.0 million for the 1 October 2023 to 31
March 2024 period, and reflected consent from the RBL banks to
increase the contribution of the Akatara project to debt capacity
in the development phase;
¡ The scheduled RBL March 2024 redetermination concluded on 26
April 2024, resulting in a borrowing base of US$200.0 million. Stag
has been removed from the borrowing base assets and replaced with
the second acquisition of 16.67% of the CWLH assets, acquired on 14
February 2024. The effective date for the redetermination and the
change to the borrowing base is 1 April 2024.
Significant and subsequent events
·
On 19 January 2023, the Group executed a sale and
purchase agreement to acquire 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 "Sinphuhorm
Assets");
·
On 22 May 2023, the Group announced the closing
of a US$200.0 million RBL facility. In support of the RBL
facility, the Group entered into a hedging program through
executing oil price swap contracts for 5.5 mmbbls over the period
Q4 2023 to Q3 2025 at an overall weighted average price of
US$70.57/bbl;
·
In June 2023, the Company raised US$51.0 million
(net of costs) through an equity placing and open offer issuing
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., the Company's
largest shareholder. As part of the underwriting
arrangement, Tyrus Capital S.A.M. and
funds managed by it, 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;
·
On 14 November 2023, the Group executed a sale
and purchase agreement with Japan Australia LNG (MIMI) Pty Ltd, to
acquire a non-operated 16.67% working interest in the Cossack,
Wanaea, Lambert, and Hermes ("CWLH Assets") oil fields development,
offshore Western Australia, for a total initial cash consideration
of US$9 million, and certain subsequent Abandonment Trust Payments
(the "Acquisition"). The Acquisition was completed on 14 February
2024, with a net receipt to the Group of US$6.3 million, reflecting
the accumulated economic benefits of the CWLH assets for the period
between the effective date of 1 July 2022 to completion. As a
result, the Group's non-operated working interest in the CWLH
assets increased to 33.33%, from 16.67%;
·
On 26 January 2024, the Group signed a Heads of
Agreement ("HoA") with PetroVietnam Gas Joint Stock Corporation
("PV Gas") for the Gas Sales and Purchase Agreement ("GSPA")
relating to the Nam Du and U Minh gas fields development offshore
Vietnam. The HoA forms the basis for negotiations over a fully
termed GSPA, which supports the submission of an updated Field
Development Plan ("FDP") for the Nam Du and U Minh fields, the
approval of which is key for progressing to a Final Investment
Decision for this project; and
·
On 13 February 2024, the ordinary shares of the
Company were suspended from trading pursuant to a proposed sale by
Woodside Energy Group Ltd. ("Woodside") of its participating
interests in the Macedon and Greater Pyrenees Projects offshore
Western Australia (the "Proposed Acquisition"). Had Jadestone been
selected as the preferred bidder and reached agreement with
Woodside on acquisition terms, the Proposed Acquisition would have
been classified as a reverse takeover transaction in accordance
with AIM Rule 14, and accordingly, the Company's ordinary shares
were suspended from trading on AIM on 13 February 2024. On 11 April
2024, Woodside cancelled the sale of its participating interests in
those assets. With the possibility of the Proposed
Acquisition ceasing, the Company's shares resumed trading on AIM on
11 April 2024.
2024 Guidance
·
The 2024 production guidance range is narrowed
from 20-23,000 boe/d to 20-22,000 boe/d. The change to the upper
end of guidance reflects average first quarter Group production
performance of c.17,200 boe/d, which was impacted by both planned
and unplanned downtime across the portfolio, particularly at the
offshore Australia assets relating to the recent cyclone season.
Current internal forecasts point to an outcome at the lower end of
the updated guidance range, based on first commercial gas sales
from Akatara in June 2024, albeit there remains a wide range of
possible outcomes, principally based on the timing and nature of
Akatara's ramp up, as well as initiatives underway to optimise
production at the Group's current producing assets. 2024 production
guidance will be kept under review, particularly in relation to the
first gas schedule at Akatara, and further updates will be provided
when appropriate;
·
2024 Group operating cost guidance is unchanged,
and is expected to total US$240.0-290.0 million (excluding forecast
royalties and carbon taxes totalling c.US$30.0 million);
and
·
2024 Group capital expenditure guidance is
unchanged, and is expected to total US$80.0-110.0 million, with
other cash expenditure still expected to total c.US$77.0 million on
a net basis, primarily reflecting the previously announced CWLH 2
acquisition abandonment funding payments.
*Restatements explained in Note 50
of the Group's consolidated financial statements.
1 2023 Production includes the Sinphuhorm Assets 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.
2
Realised oil price represents the actual selling
price inclusive of premiums.
3 Revenue in 2023 of US$309.2 million consist of a hedging loss
of US$10.3 million from the commodity swap contracts entered into
in support of the RBL facility.
4 Adjusted unit operating costs per boe, adjusted EBITDAX and
net debt/cash are non-IFRS measures and are explained in further
detail on the Non-IFRS Measures section in this
document.
Enquiries
Jadestone Energy plc.
|
|
Paul Blakeley, President and
CEO
|
+65 6324 0359
(Singapore)
|
Bert-Jaap Dijkstra, CFO
|
|
Phil Corbett, Head of Investor
Relations
|
+44 7713 687 467 (UK)
|
|
ir@jadestone-energy.com
|
|
|
Stifel Nicolaus Europe Limited (Nomad, Joint
Broker)
|
+44 (0) 20 7710 7600
(UK)
|
Callum Stewart / Jason Grossman /
Ashton Clanfield
|
|
|
|
Peel Hunt LLP (Joint Broker)
|
+44 (0) 20 7029 8000
(UK)
|
Richard Crichton / David McKeown /
Georgia Langoulant
|
|
|
|
Camarco (Public Relations Advisor)
|
+44 (0) 203 757 4980
(UK)
|
Billy Clegg / Andrew Turner /
Elfie Kent
|
jadestone@camarco.co.uk
|
Full-year 2023 presentation webcast
The Company will host an investor
and analyst presentation at 9:00 a.m. (UK time) on Monday, 29 April
2024, including a question-and-answer session, accessible through
the link below:
Webcast link: https://shorturl.at/cdgxB
Event title: Jadestone Energy
Full-Year 2023 Results
Time: 9:00 a.m. (UK
time)
Date: 29 April 2024
To join the presentation by phone,
please use the below dial-in details from the United Kingdom or the
link for global dial-in details:
United Kingdom (Local): +44 20
3936 2999
United Kingdom (Toll-Free): +44
800 358 1035
Global Dial-In Details:
https://shorturl.at/flot5
Access Code: 082963
ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG")
Jadestone is committed to being a
responsible operator, that contributes to an orderly energy
transition by helping to meet regional energy demand, whilst
bringing positive social and economic benefits for its
stakeholders, local communities and the people associated with its
operations.
HSE performance
The Group's priority remains the
health and safety of its staff, contractors and communities in
which it operates, along with ensuring that any negative
environmental impacts from operations are
minimised.
The Group maintained strong safety
performance despite elevated levels of activity and numerous and
often challenging work fronts
over 2023. Jadestone worked over 4.6 million man
hours during 2023 (2022: 1.7 million work hours), with the
year-on-year increase reflecting a full year of construction
activity at the Akatara gas development. Consequently, the total
recordable injury rate ("TRIR") of 0.86 was significantly lower
than in previous years, and comparable with the International
Association of Oil & Gas Producers ("IOGP") performance.
Overall, the Group had zero lost time injuries ("LTIs"), as well as
no material environmental incidents1.
An excellent safety record was
achieved at the Akatara gas development project site. The
EPCI2 contract was over 90% complete at 2023 year end,
with over 3.28 million manhours worked without an LTI whilst
undertaking higher risk activities such as major foundation works,
pipe rack and storage tanks construction and well workovers.
Jadestone continually engaged with the project's EPCI contractor to
ensure that robust HSE management practices were implemented and
monitored throughout the year.
Following the earlier reported
incident at Montara in 2022, the General Direction relating to the
Montara Venture FPSO tanks, which was put in place in September
2022, was lifted in February 2023. This followed completion of an
independent review of Jadestone's remediation plans and operational
readiness for the FPSO, which enabled production to re-commence
gradually in March 2023. The Prohibition Notice that was issued in
June 2022 is expected to remain open until each tank within the
FPSO that can contain oil has been inspected and a technical file
note demonstrating its fitness for service has been issued to
NOPSEMA. Jadestone is currently methodically executing a tank
restoration program, which resulted in 6 centre, 5 centre, 5 port,
5 starboard and both slops tanks being removed from the Prohibition
Notice during 2023. Work is ongoing on the remaining tanks and once
all are completed, the Prohibition Notice is expected to be fully
lifted. Jadestone continues to engage closely and transparently
with the regulator about the progress of the inspection work. The
NOPSEMA Level 4 investigation into the 2C loss of containment is
ongoing.
Net Zero interim targets
Jadestone's strategy for
maximising reserves from existing producing oil and gas fields
explicitly precludes frontier exploration and new greenfield
development, a position that is in line with the IEA's Net Zero
Emissions by 2050 Scenario. The Group is
well positioned to benefit from the energy transition as a
responsible steward of mid-life assets
divested by larger companies, committed to upholding climate
targets and executing its Net Zero by 2040 pledge.
In line with the previously
communicated timetable, Jadestone announced its interim greenhouse
gas ("GHG") emissions reduction targets in December
20233. The Company has
committed to reduce absolute Scope 1 and 2 GHG emissions from its
operated assets by 20% by 2026 and by 45% by 2030 (from 2021
levels).
The interim targets will be
achieved through a combination of measures, ranging from
operational GHG reductions, including minimising flaring as well as
reliance on carbon credits within the regulatory schemes of
Jadestone regions. For further details, refer to Jadestone's 2023
Annual Report as well as Sustainability Report, which will be
published by the end of May 2024.
1 Defined as events leading to minor effect, recovery in weeks
to months or higher as per Group's risk matrix.
2 Engineering, Procurement, Construction and
Installation.
3 The detail of this announcement can be viewed on
Jadestone's website.
In 2023, the Group's Scope 1 GHG
emissions from operated sites were 469 kt of CO2-e,
slightly below the previous year (2022: 489 kt of
CO2-e). Levels of GHG emissions were significantly below
forecast and reflected the downtime at Montara until late March
2023 and then during August 2023 as FPSO operations were gradually
restored following tank repair works. Jadestone's indirect, Scope 2
GHG emissions from the consumption of purchased electricity across
its offices and warehouses account for less than 1% of its total
Scope 1 and 2 emissions combined. Jadestone does not consume any
purchased electricity at any of its operated sites.
Governance
Jadestone's Board has undergone a
number of changes during 2023 and the first quarter of 2024 with
the longer-term objective to ensure that the Board is sized
appropriately to the Company's scale and ambition, while
maintaining the right capabilities and adhering to corporate
governance standards.
On 18 October 2023, the Company
announced the appointment of Gunter Waldner as a non-executive
director. Mr. Waldner will stand for election at the Company's 2024
Annual General Meeting. Mr. Waldner was nominated as a
non-executive director by the Company's largest shareholder, Tyrus
Capital S.A.M. and funds managed by it ("Tyrus"), pursuant to the
relationship agreement entered into by the Company and Tyrus in
November 2018. Mr. Waldner brings significant knowledge of and
experience in corporate finance and acquisition
strategy.
On 25 January 2024, the Company
announced the appointment of Joanne Williams as an independent
non-executive director. Ms. Williams is a reservoir engineer with
more than 25 years' experience in technical and executive roles.
Ms. Williams is Chair of both the HSEC Committee and the Montara
Technical Committee, and a member of the Audit
Committee.
On 25 March 2024, the Company
announced the appointment of Adel Chaouch as an independent
non-executive director. Mr. Chaouch possesses significant
upstream operations and executive experience. On 25 March 2024, the
Company also announced the resignation of (i) Lisa Stewart as an
independent non-executive director and (ii) Robert Lambert as an
independent non-executive director.
On 27 March 2024, the Company
announced the resignation of Dennis McShane as an independent
non-executive director and Chair of the Board.
Also on 27 March 2024, the Company
announced the election of Adel Chaouch as Chair of the Board.
Dr. Chaouch is Chair of the Governance and Nomination Committee,
and a member of both the Remuneration Committee and the HSEC
Committee.
As previously announced, Iain
McLaren has signalled an intention to step down as an independent
non-executive director and Chair of the Audit Committee once a
replacement has been appointed. The Board is progressing the
recruitment of an appropriate candidate.
OPERATIONAL REVIEW
Producing Assets
Australia
Montara Project
The Montara Project, in production
licences AC/L7 and AC/L8, is located 254 km offshore Western
Australia, in water depth of approximately 77 metres. The Montara
Project comprises three separate fields being Montara, Skua and
Swift/Swallow, which are produced through an owned FPSO, the
Montara Venture.
As at 31 December 2023, the
Montara assets had proven plus probable reserves of
13.6 mmbbls (31 December
2022: 18.5 mmbbls), 100% net to Jadestone. The year-on-year change
in reserves at Montara is explained by production in the year (1.3
mmbbls) and a 3.5 mmbbls downgrade to reflect revisions to well
performance, timing and nature of future infill drilling activity,
and higher anticipated operating costs over life of
field.
The fields produce light sweet
crude (42o API, 0.067% mass sulphur), which typically sells for average
Dated Brent plus the average Tapis differential in the month of
lifting. The premium in 2023 ranged between US$1.36/bbl to
US$6.59/bbl, with an average premium of US$3.82/bbl. The most
recent lifting in March 2024 was agreed at a premium of
US$3.88/bbl.
Production from the Montara fields
was 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 late in March 2023.
On 29 July 2023, production at
Montara was temporarily shut in following a hydrocarbon gas alarm
in ballast water tank 4S. Production restarted on 1 September 2023
with tank 6C. Inspections identified the location of a small
defect between tank 4S and oil cargo tank 5C, with the repairs of
both tanks completed in Q1 2024 and returned to service
thereafter.
On 4 October 2023, pressure was
lost from the A annulus in the Skua-11 well, likely as a result of
gas in the annulus escaping from a shallow leak point. The well was
immediately shut in. A replacement operation, which includes a
sidetrack to target volumes associated with Skua-11 and additional
reserves in the vicinity is currently being planned and is expected
to commence in Q4 2024.
Montara production averaged 3,655
bbls/d in 2023 (2022: 4,227 bbls/d), lower compared to previous
year due to facility constraints caused by
the separator limitations from March to July 2023 and the limited
storage tank capacity on the FPSO due to the repair and maintenance
activities referenced above.
There were five liftings in 2023,
resulting in total sales of 1.2 mmbbls of crude oil compared to 1.7
mmbbls from the same number of liftings in 2022.
Stag oilfield
The Stag oilfield, in production
licence WA-15-L, is located 60 km offshore Western Australia in a
water depth of approximately 47 metres.
As at 31 December 2023, the field
contained total proved plus probable reserves of
11.1 mmbbls (31 December
2022: 12.1 mmbbls), 100% net to Jadestone. The majority of the
year-on-year change in reserves was explained by production during
the year.
The Stag oilfield produces heavy
sweet crude (18o
API, 0.14% mass sulphur), which historically
sells at a premium to Dated Brent. The premium in 2023 ranged
between US$10.10/bbl and US$19.10/bbl with an average premium of
US$ 13.03/bbl. The most recent lifting in March 2024 was agreed at
a premium of US$15.88/bbl.
Production was 2,672 bbls/d in
2023 compared to 2,176 bbls/d in 2022. This increase was
predominately due to the completion of the Stag 50H and 51H
drilling campaign in November 2022.
There were four liftings in 2023
for total sales of 1.0 mmbbls, compared to 0.8 mmbbls in 2022 from
the same number of liftings.
The Group made an impairment
charge of US$17.4 million to Stag's oil and gas properties as at 31
December 2023, following an annual impairment assessment performed
and identified that the VIU of the operating asset is lower than
the carrying amount (see Financial Review section in this
document).
North West Shelf
Project
The Cossack, Wanaea, Lambert and
Hermes oil fields (the "CWLH
Assets") are located 115km offshore
Western Australia in production licences WA-3-L, WA-9-L, WA-11-L
and WA-16-L situated in a water depth of approximately 80
metres.
As at 31 December 2023, the CWLH
Assets contained total proved plus probable reserves of
6.8 mmbbls (31 December
2022: 5.1 mmbbls), net to Jadestone. The year-on-year increase
reflects the outperformance of the CWLH assets during 2023, with
higher uptime and lower decline rates incorporated into the
end-2023 reserves assessment, with asset life now extending to 2035
(from 2031) as a result. The end-2023 CWLH Assets reserves figure
above does not include the recent doubling of the Group's interest,
which is described below.
On 14 November 2023, the Group
executed a sale and purchase agreement with Japan Australia LNG
(MIMI) Pty Ltd (the "Seller"), to acquire the Seller's non-operated
16.67% working interest in the CWLH Assets, for a total initial
cash consideration of US$9 million, and certain subsequent
Abandonment Trust Payments (the "Acquisition").
The Acquisition was completed on
14 February 2024, with a net receipt to the Group from the Seller
of US$6.3 million, reflecting the accumulated economic benefits of
the CWLH assets for the period from the effective date of 1 July
2022 to completion. As a result, the Group's non-operated working
interest in the CWLH assets increased to 33.33%, from
16.67%.
On 9 February 2024, the US$6.3
million net receipt from the Seller and US$35.7 million from
Jadestone were paid into the CWLH abandonment trust fund, in
aggregate satisfying the initial US$42.0 million abandonment
funding requirement required under the terms of the Acquisition.
The second US$23.0 million instalment into the abandonment trust
fund is payable on NOPTA's approval of the accession documents,
which is expected in Q2 2024. The final instalment of up to US$37.0
million will be paid into the abandonment trust fund by 31 December
2024.
Contribution to Group production
was 1,896 bbls/d in 2023 compared to 383 bbls/d in 2022 on an
annualised basis, due to the timing of the acquisition. The average
production from the completion date of 1 November 2022 to 31
December 2022 was 2,290 bbls/d, net to Jadestone's working
interest.
Jadestone lifted one cargo in 2023
for total sales of 0.7 mmbbls, compared to 0.7 mmbbls in 2022, also from one lifting.
Malaysia
Operated: PM 323 and PM 329, PM
318 and AAKBNLP PSCs
The PenMal Assets consist of two
operated PSCs, which comprise a 70% interest in PM329 PSC,
containing the East Piatu field, and a 60% interest in PM323 PSC,
which contains the East Belumut, West Belumut and Chermingat
fields.
Additionally, the Group assumed
100% working interests in PM318 and AAKBNLP PSCs (the "PNLP
Assets") after taking over operatorship in April 2023 following the
decision of the previous operator to withdraw from the licences.
As a result, the Group acquired the rights over the 50% of
abandonment cess fund and assumed the remaining 50% of asset
restoration obligations under the PNLP Assets. As part of the
takeover, the previous operator paid the Group for a sum
representing its share of future wells
preservation activities and decommissioning costs.
The Group believes that the PNLP Assets have
significant reserve and resource potential. Jadestone is
currently overseeing operations and maintenance in shut-in
mode. In June 2023, the Group submitted a business value
proposition to PETRONAS outlining plans to redevelop the PNLP
Assets and resume production. The PNLP Assets were included in the
Malaysia Bid Round Plus ("MBR+") process in October 2023 and
renamed as the "Puteri Cluster". The reinstatement of production
and further development of the Puteri Cluster by the Group is
subject to retaining the licence as part of the MBR+ process. The
Group has submitted a bid for the Puteri Cluster, with the results
of the MBR+ process anticipated in mid-2024.
All four PSCs are located
approximately 230km northeast of Terengganu in shallow
water.
As at 31 December 2023, PM323 and
PM329 PSCs contained total proved plus probable reserves of
9.2 mmboe (2022: 8.9
mmboe), net to Jadestone. The year-on-year increase can be
primarily explained by a reserve upgrade at PM323 PSC following the
successful infill drilling campaign in late 2023 and offset by
production during the year.
The PenMal Assets produce light
sweet crude that is blended to Tapis grade
(43o API, 0.04% mass sulphur). The premium in 2023 ranged between
US$2.72/bbl to US$5.63/bbl with an average premium realised of
US$4.38/bbl. The most recent lifting in March 2024 was agreed at a
premium of US$4.16/bbl.
Production in 2023 was 3,664
bbls/d of oil and 3,744 mscf/d of gas, or 4,288 boe/d, net to
Jadestone's working interest, compared to 3,884 bbls/d of oil and
4,908 mscf/d of gas, or 4,702 boe/d in 2022. The year-on-year
decrease is due to natural production decline at the PM329 PSC only
being partly offset by the initial contribution of the new PM323
infill wells drilled in late 2023, and no production from the PNLP
Assets reflecting the current shut-in mode.
The East Belumut (PM323 PSC)
infill campaign, which commenced in August 2023, was very
successful, with first oil achieved two months earlier than
expected. By adding four new horizontal oil producers, field
production was quadrupled and exceeded target, with incremental
gross oil production of c.8,000 bbl/d. The infill campaign
delivered incremental gross reserves of 4.2 mmbbls, including 1.3
mmbbls from the existing wells on the field after the economic
limit was extended by c.3 years.
There were nine liftings from the
PenMal Assets in 2023, resulting in total oil sales of 0.8 mmbbls
and total gas sales of 1.4 mmscf, compared to total oil sales of
0.8 mmboe and total gas sales of 1.8 mmscf from 13 liftings in
2022.
Thailand
APICO LLC (Sinphuhorm gas field
and Dong Mun gas discovery)
On 23 February 2023, the Group
closed the acquisition of interests 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). The cash consideration was
US$27.8 million, based on an effective date of 1 January
2022.
As at 31 December 2023, the
Sinphuhorm Assets contained proved plus probable reserves of 3.9
mmboe, net to Jadestone.
The Group's 9.52% non-operated
working interest in the Sinphuhorm Assets enables the Group to
exercise significant, being the power to participate in the
financial and operating policy decisions, but not control or joint
control over the assets' day-to-day operations. Therefore, the
Group does not recognise its share of revenues and production
costs, instead recognising dividend income
when received. The Group received US$3.7 million of dividends in
2023.
Average production since the date
of acquisition was 1,450 boe/d, contributing 1,303 boe/d to Group
annual production in 2023.
Pre-production Assets
Indonesia
Lemang PSC
The Lemang PSC is located onshore
Sumatra, Indonesia. The PSC contains the Akatara field, which has
been de-risked with 11 wells drilled into the structure, plus three
years of oil production history, up until the field ceased oil
production in December 2019. Jadestone is redeveloping
Akatara to supply gas, condensate and LPGs for local and regional
use.
The Akatara gas field has been
independently estimated to contain 2P gross reserves (pre local
government back-in rights) of 81.4 bcf of sales gas, 2.8 mmbbls of
condensate and 9.5 mmboe of LPG, equating to a combined 25.9 mmboe
of reserves. Jadestone has a 100% interest in the Lemang PSC, with
the local government retaining a back-in right for a 10%
participating interest. The Group expects the local government to
take the 10% interest from its back-in rights, a process which is
currently going through a due diligence phase.
During 2023, the Group's primary
focus was on the civil foundation works, control and electrical
buildings, erection of the LPG, condensate
and fire water tanks, and the main
pipe-rack. This was followed by installation of the static and
rotating equipment, installation of piping, and
electrical/instrumentation cables, including the sales gas
pipeline, flowlines modification and the gas metering station. By
the end of December 2023, all of the key long-lead items had
arrived on site.
Currently, the Group is focused on
testing all equipment, testing, cleaning
and reinstatement of interconnecting
pipe, electrical and instrument testing at
both the gas plant and metering station,
and the hydrotesting of the gas pipeline. Overall progress of
the project had reached 95.72% completion at the end of March 2024.
Pre-commissioning and commissioning activities commenced in
November 2023 and continued into early Q1 2024 for utility systems,
with further progression towards commissioning for the process
system. Commercial production remains on track to start in Q2
2024.
In June 2023, the Group
successfully reactivated two wells from the prior oil development
on the Akatara field. During testing, one well achieved a maximum
flow rate of approximately 9 million cubic
feet per day (mmcf/d), with data from the
well test supporting the current Akatara 2P reserves estimate. The
well is designated to supply
pre-commissioning and commissioning gas for the AGPF, while the
second well is intended for use as an injector/disposal
well.
A campaign with a 550 HP rig to
work-over the planned five wells commenced in Q1 2024. Currently,
four out of five well workovers have been completed and tested at
an aggregate stabilised rate of c.30 mmcf/d, ready to deliver the
gas production required to fulfil the daily contract quantity under
the gas sales agreement.
Vietnam
Block 51 and Block 46/07
PSCs
Jadestone holds a 100% operated
working interest in the Block 46/07 and Block 51 PSCs, both in
shallow water in the Malay Basin, offshore southwest
Vietnam.
The two contiguous blocks hold
three discoveries: the Nam Du gas field in Block 46/07 and the U
Minh and Tho Chu gas/condensate fields in Block 51, with aggregate
2C contingent resources of 93.9 mmboe.
Throughout 2023, the Group
negotiated a gas sales heads of agreement ("HoA") with Petrovietnam
Gas Joint Stock Corporation ('PV Gas'). The key terms were
finalised after receiving approval from PV Gas, Petrovietnam, and
Jadestone, with the HoA signed on 25 January 2024.
The HoA enables the submission of
an updated Nam Du/U Minh Field Development Plan for approval, which
is required before a final investment decision can be taken and
commercialisation of this potential resource advanced.
Exploration phase two of the Block
46/07 PSC includes a commitment to drill one exploration well.
Jadestone proposes to drill this well in conjunction with drilling
the gas production wells for the Nam Du field development and to
utilise the well as a future gas producer via the Nam Du/U Minh
processing facilities. Exploration phase two is due to expire on 29
June 2024. The Group has submitted a request to Petrovietnam to
extend the drilling deadline to align the timing of the commitment
well with the Nam Du/U Minh project schedule. This approach is
consistent with previous extensions granted for the PSC exploration
phase two.
The Tho Chu discovery in Block 51
was under a suspended development area status. The Company is
working with Petrovietnam and other government entities to obtain a
suspension of the relinquishment obligation for Block
51.
Reserves and resources
Total 2P Reserves (net, mmboe)
|
|
Australia
|
Malaysia2
|
Indonesia2
|
Thailand
|
Total
Group
|
Opening balance, 1 January 2023
|
35.6
|
8.9
|
20.3
|
0.0
|
64.8
|
Acquisitions
|
-
|
-
|
-
|
4.2
|
4.2
|
Technical revisions
|
(1.0)
|
1.9
|
3.0
|
0.2
|
4.1
|
Production
|
(3.0)
|
(1.6)
|
-
|
(0.5)
|
(5.1)
|
Ending balance, 31 December 2023
|
31.6
|
9.2
|
23.3
|
3.9
|
68.0
|
As at 31 December 2023, the Group
had proved plus probable oil reserves ("2P Reserves") of 68.0
mmboe, a 5% increase compared with 31 December 2022 and
representing 164% 2P reserve replacement during the
year.
2P reserves of 4.3 mmboe were
booked on closing of the Sinphuhorm acquisition in February 2023.
There was a reserve upgrade at the CWLH fields offshore Australia
due to better than expected asset performance during the year, in
turn extending field life from 2031 to 2035. Reserves also
increased at the PM323 field offshore Malaysia due to the
successful infill drilling campaign in the second half of 2023. An
additional 3.0 mmboe of 2P reserves were booked at the Akatara
field, representing the volumes committed under a further gas sales
agreement negotiated during the year. These positive moves were
balanced by a 3.5 mmbbls reduction in reserves at Montara, due to
the forecast of higher operating costs over the life of the field,
and a small negative revision at the PM329 asset offshore Malaysia.
Jadestone completed the acquisition of an additional 16.67%
interest in the CWLH fields, adding a further 6.8 mmboe of 2P
Reserves at closing, after the period end and was therefore not
included in end-2023 reserves calculation.
ERCE independently evaluated the
Group's year-end 2023 reserves.
Total 2C Contingent Resources3 (net,
mmboe)
|
|
Australia
|
Malaysia
|
Indonesia2
|
Thailand
|
Vietnam2
|
Total
Group
|
Opening balance, 1 January 2023
|
6.5
|
-
|
3.9
|
0.0
|
93.9
|
104.3
|
Acquisitions
|
-
|
-
|
-
|
2.5
|
-
|
2.5
|
Transfer to 2P reserves
|
(2.4)
|
-
|
(3.0)
|
-
|
-
|
(5.4)
|
Technical revisions
|
1.1
|
1.2
|
-
|
1.9
|
-
|
4.2
|
Ending balance, 31 December 2023
|
5.1
|
1.2
|
0.9
|
4.4
|
93.9
|
105.6
|
The Group's best case contingent
resources ("2C resources") increased slightly from 104.3 mmboe in
2022 to 105.6 mmboe in 2023. The partial reclassification of
Akatara and CWLH contingent resources to 2P reserves was more than
offset by the inclusion of the Group's share of future (2025)
infill targets at PM323 and PM329, contingent resources associated
with a potential life extension of Sinphuhorm field life and the
CWLH fields, and contingent resources associated with the Dong Mun
discovery onshore Thailand (acquired with the interest in the
Sinphuhorm field).
1 Proven and Probable Reserves for Jadestone's assets have been
prepared in accordance with the June 2018 SPE/WPC/AAPG/
SPEE/SEG/SPWLA/EAGE Petroleum Resources Management System ("PRMS")
as the standard for classification and reporting.
2 Assumes oil equivalent conversion factor of 6,000
scf/boe.
3 Contingent Resources based on ERCE estimates as at 31
December 2022, except for Vietnam 2C resources which are based on
ERCE Competent Person's Report effective 31 December
2017.
FINANCIAL REVIEW
The following table provides
select financial information of the Group, which was derived from,
and should be read in conjunction with, the consolidated financial
statements for the year ended 31 December 2023.
USD'000 except where
indicated
|
2023
|
2022
Restated*
|
|
|
|
Sales volume, barrels of oil
equivalent (boe)
|
3,862,741
|
4,326,770
|
Production,
boe/day1
|
13,813
|
11,487
|
Realised oil price per barrel of
oil equivalent (US$/boe)2
|
87.34
|
103.85
|
Realised gas price per
thousand standard cubic feet (US$/mscf)
|
1.53
|
1.63
|
Revenue3
|
309,200
|
421,602
|
Production costs
|
(232,772)
|
(250,300)
|
Adjusted unit operating costs per
barrel of oil equivalent (US$/boe)4
|
37.24
|
37.49
|
Adjusted
EBITDAX4
|
90,647
|
162,329
|
Unit depletion, depreciation & amortisation
(US$/boe)
|
14.14
|
10.74
|
Impairment of assets
|
(29,681)
|
(13,534)
|
(Loss)/Profit before
tax
|
(102,766)
|
63,193
|
(Loss)/Profit after tax
|
(91,274)
|
9,237
|
(Loss)/Earnings per ordinary
share: basic & diluted (US$)
|
(0.18)
|
0.02
|
Operating cash flows before
movement in working capital
|
36,499
|
158,548
|
Capital expenditure
|
115,882
|
82,876
|
Net
(debt)/cash4
|
(3,596)
|
123,329
|
Benchmark commodity price and realised
price
The actual average realised price
in 2023 decreased in line with the benchmark price, which decreased
by 16% to US$87.34/bbl, from US$103.85/bbl in 2022. The primary
factor was the downturn in the benchmark Brent price, which fell by
18% to US$82.64/bbl compared to US$101.32/bbl in 2022. The average
realised premium for the year was US$5.58/bbl, compared to
US$7.81/bbl in 2022, generally following the lower average Brent
price. The Stag premium averaged US$13.03/bbl (2022: 22.78/bbl),
Montara premium was US$3.82/bbl (2022: US$4.70/bbl) and PenMal
operated assets premium came in at US$4.38/bbl (2022:
US$6.67/bbl).
*Restatements explained in Note 50
of the Group's consolidated financial statements.
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 the Group only recognises
dividends received. Accordingly, the revenue and production costs
from the Sinphuhorm Assets are excluded from the Group's financial
results.
2 Realised oil price represents the actual selling price
inclusive of premiums.
3 Revenue in 2023 of US$309.2 million consist of a hedging loss
of US$10.3 million from the commodity swap contracts entered into
in support of the RBL facility.
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 Group achieved average
production of 13,813 boe/d in 2023, an increase from 11,487 boe/d
in 2022. The overall increase was as a result of the following key
factors:
· Higher annualised production at the
CWLH Assets of 1,896 bbls/d for the full year in 2023 compared to
two months in 2022 of 383 bbls/d;
· Acquisition of the Sinphuhorm Assets in February 2023
contributing to annualised production of 1,303 boe/d;
and
· Stag
production increased by 496 bbls/d attributable to the additional
output from the successful drilling and completion of 50H and 51H
wells in November 2022.
The increase was partly offset
by:
· Lower production from Montara by 572 bbls/d as a result
of the facility constraints caused by the
separator limitations from March to July and tank tops arising from
the limited storage tank capacity on the FPSO ; and
· Reduced production from the PenMal Assets by 414 bbls/d due
to higher unplanned downtime of the Chermingat platform combined
with natural field decline.
Throughout the year, the Group
executed 19 liftings, a decrease from the 22 liftings in 2022,
leading to oil sales totaling 3.6 million barrels (mmbbls), down
from 4.0 mmbbls in 2022. This reduction in lifted volumes was
caused by lower production levels at the Montara and PenMal
Assets.
The Group recorded a sale of
1,366.5 mmscf of gas from the PenMal Assets, compared to 1,791.1
mmscf of gas in 2022.
Revenue
The Group generated net revenue
after the effect of hedging of US$309.2 million in 2023, a decrease
of 24% compared to 2022 of US$421.6 million. The decrease of
US$112.4 million was predominately due to:
· Lower average realised prices in 2023 of US$87.34/bbl (2022:
US$103.85/bbl), resulting in decreased revenue of US$66.6
million;
· A
hedging loss of US$10.3 million incurred from the
commodity swap contracts entered into following
the execution of the RBL facility;
· A
reduction in lifted volumes by 0.4 mmboe year-on-year resulting in
decreased revenue of US$34.4 million; and
· PenMal Assets generating lower gas revenue of US$2.0 million
compared to US$3.1 million in 2022.
Production costs
Production costs decreased by 7%
in 2023 to US$232.8 million, from US$250.7 million in 2022,
amounting to a decrease of US$17.5 million. The reduction was predominately
due to the following factors:
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
Variance
USD'000
|
|
Note
|
|
|
|
|
|
|
|
|
|
Operating costs
|
|
98,723
|
|
74,283
|
|
24,440
|
|
(i)
|
Supplementary payments and
royalties
|
|
16,056
|
|
26,381
|
|
(10,323)
|
|
(ii)
|
Workovers
|
|
17,562
|
|
10,190
|
|
7,372
|
|
(iii)
|
Logistics
|
|
34,109
|
|
31,895
|
|
2,214
|
|
(iv)
|
Repairs and maintenance
|
|
55,572
|
|
60,174
|
|
(4,602)
|
|
(v)
|
Decommissioning
expenses
|
|
12,545
|
|
-
|
|
12,545
|
|
(vi)
|
Underlift, overlift and crude
inventories movement
|
|
(9,297)
|
|
39,036
|
|
(48,333)
|
|
(vii)
|
Tariffs and transportation
costs
|
|
7,502
|
|
8,341
|
|
(839)
|
|
(viii)
|
|
|
|
|
|
|
|
|
|
|
|
232,772
|
|
250,300
|
|
(17,526)
|
|
|
(i)
Overall operating costs increased by US$24.4 million to US$98.7
million in 2023, compared to US$74.3 million in 2022, due
to:
- Operating costs at
Montara and Stag increased by US$20.8 million (2023: US$77.0
million; 2022: US$56.2 million), primarily due to US$14.3 million
related to the hire of a crude tanker to compensate for reduced
Montara FPSO tank capacity and US$1.0 million incurred for the
non-recurring disposal of NORMs (naturally occurring radioactive
material). Stag tanker costs increased by US$5.8 million
compared to 2022 reflecting higher tanker rates in 2023;
- A full year of
operations at the CWLH Assets, compared to two months in 2022,
resulted in an increase in operating costs by US$13.6
million;
- Operating costs at the
PenMal Assets decreased by US$10.0 million to US$5.2 million in
2023, down from US$15.2 million in 2022. This reduction was
primarily due to reduced chemical consumption at the operated
assets. Additionally, the decrease was associated with the
continued suspended production at the PNLP Assets in
2023;
(ii)
Supplementary payments and royalties decreased by US$10.3 million
in 2023 totalling US$16.1 million, compared to US$26.4 million in
2022. The supplementary payments at the PenMal Assets decreased by
US$14.0 million to US$10.5 million (2022: US$24.5 million) due to
lower realised price compared to 2022, as the payments are based on
the differential between the realised price and the escalated PSC
base price. The decrease was partly offset by higher royalties paid
by the CWLH Assets for the levy on the wellhead value for a primary
production licence in 2023 of US$3.5 million (2022: US$0.8
million);
(iii)
Workover costs rose by US$7.4 million to US$17.6 million compared
to US$10.2 million in 2022. The increase was mainly due to the
completion of 10 workovers at Stag in 2023, including nine standard
routine workovers and one complex well integrity repair, compared
to four standard routine workovers in 2022. The increase was
partially mitigated by a decrease in workover costs of US$2.4
million at Montara;
(iv)
The increase of US$2.2 million in logistical
costs was mainly driven by the PenMal Assets, which was
attributable to cargo handling charges resulting from a higher
charge rate and higher frequency of personnel
mobilisation/demobilisation and material/equipment costs at the
operated assets;
(v)
Repair and maintenance ("R&M") costs decreased by US$4.6
million to US$55.6 million in 2023 compared to US$60.2 million in
2023. Montara and Stag incurred higher R&M in 2022 by US$5.8
million mainly for Skua-11 repair works, solar engine change out
and emergency tank repairs. The year-on-year reduction at Montara
and Stag was partly offset by higher R&M at the PenMal Assets
of US$1.2 million in 2023 for the repair of a gas turbine generator
at the PM329 PSC;
(vi)
The PenMal Assets incurred US$12.5 million cost, net to Jadestone's
share, for decommissioning work scope performed by the previous
operator of the PNLP Assets on the Bunga Kertas FPSO;
(vii)
The variance of US$48.3 million is mainly
driven by the first time recognition of
the overlift position (US$34.0 million) in 2022.
The overlift at the CWLH Assets as at the end of
2023 generated a credit to production costs of US$0.4 million
compared to a charge of US$33.6 million in 2022 reflecting the
first time recognition of overlift at acquisition in November
2022.
Montara and Stag ended the year
with a combined increase in crude inventories of 120,580 bbls
compared to the beginning of 2023, generating a credit of US$6.2
million. In comparison, at the end of 2022, Montara and Stag had a
lower combined inventories on hand, resulting in a decrease of
183,422 bbls compared to beginning of 2022, generating a charge of
US$3.4 million.
The underlift at the PenMal Assets
created a credit to production cost of US$2.7 million compared to a
charge of US$2.0 million as a result of the overlift position at
2022 year end; and
(viii) Tariffs and
transportation costs were incurred at Montara, Stag and the PenMal
Assets. The year-on-year movement is not significant.
Unit operating costs per barrel of
oil equivalent (boe) at US$37.24/boe were largely unchanged in 2023
compared to US$37.49/boe in 2022 (refer to
the Non-IFRS measures section below in this
document).
*Restatements explained in Note 50
of the Group's consolidated financial statements.
Depletion, depreciation and amortisation
("DD&A")
DD&A charges were US$76.1
million during the year, compared to US$61.6 million in 2022, with
the increase predominately due to the higher production at Stag and
a full year production at the CWLH Assets, resulting in an increase
of US$8.1 million and US$3.0 million, respectively. Additionally,
the PenMal Assets recorded a higher DD&A charge by US$7.0
million compared to 2022 due to the drilling campaign undertaken at
PM323 PSC during the second half of 2023, resulting in an increase
of production during Q4 2023. These increases were partly offset by
a crude inventory credit of US$4.2 million (2022: charge of US$2.9
million) as both Montara and Stag ended the year with higher crude
inventories on hand compared to beginning of 2023, whereas both
assets had a lower crude inventory on hand at the end of 2022
compared to beginning of year.
Depreciation of the Group's
right-of-use assets increased to US$15.3 million in 2023 from
US$13.0 million in 2022, primarily due to the extension of the
Group's helicopter lease and Montara warehouse lease for three
years and two years, respectively, plus a two-year lease for a
Montara support vessel replacing an expired lease.
The depletion cost on a unit basis
was US$14.14/boe in 2023 (2022: US$10.74/boe), due to higher
combined depletion costs per unit at both Montara and Stag in 2023
at US$21.68/bbl (2022: US$17.35/bbl) 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. The unit
depletion costs in 2023 for the PenMal Assets was US$6.40/boe
compared to US$1.76 /boe in 2022, due to the drilling campaign
undertaken at PM323 PSC during H2 2023.
Staff costs
Total staff costs in 2023 were
US$56.2 million, comprising US$26.0 million (2022: US$26.1 million)
in relation to offshore employees, recorded under production costs,
and US$30.2 million (2022: US$29.2 million) for office-based
employees. The average number of employees during the year was 409
(2022: 369), with the additional staff costs and headcount
year-on-year mainly at Indonesia for the ramp up of activities at
the Akatara development project. The remaining increase come
from the operations in Australia and Malaysia, which have seen
marginal expansion across the assets.
Other expenses
Other expenses increased in 2023
to US$22.8 million (2022: US$22.3 million). The variance of US$0.5
million was predominately due to:
|
|
2023
USD'000
|
|
2022
USD'000
|
|
Variance
USD'000
|
|
Note
|
|
|
|
|
|
|
|
|
|
Non-recurring corporate
costs
|
|
3,602
|
|
1,119
|
|
2,483
|
|
(i)
|
Recurring corporate costs and
other expenses
|
|
11,742
|
|
9,431
|
|
2,311
|
|
(ii)
|
Change in provision - Lemang PSC
contingent payments
|
|
-
|
|
7,333
|
|
(7,333)
|
|
(iii)
|
Allowance for slow moving
inventories
|
|
655
|
|
3,768
|
|
(3,113)
|
|
(iv)
|
Assets written off
|
|
5,114
|
|
212
|
|
4,902
|
|
(v)
|
Net foreign exchange
loss
|
|
1,728
|
|
442
|
|
1,286
|
|
(vi)
|
|
|
|
|
|
|
|
|
|
|
|
22,841
|
|
22,305
|
|
536
|
|
|
(i)
An increase in non-recurring costs by US$2.5 million compared to
2022. In 2023, the Group incurred non-recurring costs including
advisory and consulting fees for business development of US$2.2
million, an internal re-organisation for US$0.8 million, US$0.4
million for the equity fundraise in June 2023 and an aggregate of
US$0.2 million for the Interim Facility, RBL facility and commodity
swap contracts. In comparison, the Group incurred total
non-recurring costs of US$1.1 million in 2022 related to the
acquisition of CWLH Assets, business development and other one-off
projects;
(ii)
An increase in corporate costs and other expenses by US$2.3 million
to US$11.7 million in 2023 (2022: US$9.4 million) across all
operating countries;
(iii)
The 2022 costs included the recognition of additional contingent
payments related to the future Dated Brent prices and Saudi CP
prices associated with the Lemang PSC of US$7.3 million. Following
the 2023 year-end assessment, these contingent payments were
derecognised with the associated credit booked in other income (see
note below). The Group did not recognise new contingent payments in
2023;
(iv)
The Group provided an allowance for slow moving inventories of
US$0.7 million during the year, compared to US$3.8 million in 2022,
following the assessment performed.
(v)
Assets written off amounted to US$5.1 million in 2023 (2022: US$0.2
million), which included the write-off of the non-depletable oil
and gas properties at Montara for US$3.1 million following the
cancellation of a capital project for the preparation of Skua-12
well, and the write-off of obsolete material and spares for US$2.0
million. In 2022, the Group wrote off US$0.2 million for plant and
equipment associated with its New Zealand operations following the
withdrawal from Maari acquisition; and
(vi)
Net foreign exchange loss of US$1.7 million in 2023 (2022: US$0.4
million) mainly arising from the Group's receivables denominated in
Malaysian Ringgit ("MYR") due to the volatility of MYR against USD
towards the end of 2023.
Finance costs
Finance costs in 2023 were US$41.8
million (2022: US$11.4 million), an increase of US$30.4 million,
predominately due to:
· Warrants expense of US$3.5 million arose from the warrants
for 30 million ordinary shares received by Tyrus in connection with
the underwriting debt facility in support of the June 2023 equity
placing;
· ARO
accretion expense increased by US$11.9 million to US$20.2 million
compared to US$8.3 million in 2022, resulting from an increase in
the ARO at Stag and Montara as assessed at year-end
2022;
· Upfront fees of US$2.7 million (2022: nil) and interest of
US$1.0 million (2022: nil) were incurred in association with the
equity underwrite debt facility and committed standby working
capital facility executed with Tyrus
Capital Events S.a.r.l.;
· RBL
accretion expense of US$5.5 million (2022: nil) reflecting the time
value of money and RBL commitment fees of US$0.3 million (2022:
nil);
· Interest expense and other finance costs increased by US$3.6
million to US$3.7 million compared to US$0.1 million in 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). Additionally, the Group
incurred accretion expense of US$0.6 million generated from an Australian Tax Office repayment plan for
corporate tax payments;
· Interest on lease liabilities increased by US$2.0 million to
US$2.8 million compared to US$0.8 million in 2022, following the
lease extensions for helicopters, vessel and warehouse at Montara;
and
· Changes in fair value of contingent payments in 2023 of
US$0.9 million, a US$1.0 million decrease compared to US$1.9
million in 2022.
Other income
The Group generated US$18.9
million of other income during 2023 compared to US$28.0 million in
2022, predominately due to:
· Interest income from the CWLH Assets decommissioning trust
fund of US$2.9 million (2022: US$0.1 million) and US$1.0 million
(2022: nil) from the placement of fixed deposits;
· Reversal of provisions associated with the Lemang PSC's
contingent payments in 2023 of US$7.7 million being the
derecognition of contingent payments associated with the Saudi CP
and Dated Brent prices, as the trigger events are not expected to
occur; and
· In
2022, other income included insurance claim receipts of US$18.0
million compensating for the loss of production at Montara related
to drilling activities at the Skua-10/11 wells in
2021.
Share of result of associates
Since the acquisition of the
Sinphuhorm Assets in February 2023, the Group recognised its share
of profits amounting to US$2.6 million for the period up to 31
December 2023.
Impairment
During the year, the Group made an
impairment to the Stag's oil and gas properties carrying value of
US$17.4 million following the annual impairment assessment, which
identified that the recoverable amount of the operating asset is
lower than its carrying amount.
Additionally, the Group also
recorded an impairment related to the PNLP Assets' oil and gas
properties of US$12.3 million resulting from a revision of ARO
estimates. The revised ARO is capitalised but immediately impaired
because management does not currently anticipate future economic
inflows from the PNLP Assets, given the uncertainty
regarding a potential
restart of production. The Group fully
impaired the PNLP Assets' oil and gas
properties in 2022.
Taxation
The tax credit of US$11.5 million
in 2023 (2022: US$54.0 million of tax charge) includes a current
tax charge of US$10.8 million (2022: US$27.1 million) and a
deferred tax credit of US$22.3 million (2022: deferred tax charge
of US$26.9 million).
During the year, tax payments
comprised US$5.3 million (2022: US$18.5 million) for Australian
corporate taxes and US$1.7 million (US$1.1 million) for PRRT
payments. Additionally, there were US$7.5 million (2022: US$15.7
million) in Malaysian petroleum income tax ("PITA")
payments.
The weighted average effective tax
rate for operating jurisdictions in Australia and Malaysia was
negative 54% in 2023, reflecting losses incurred during the year,
compared to 56% in 2022, which was attributable to profits
generated during that year. There was an
increase in the deferred tax asset during 2023, resulting from
income tax credits as the trading losses are carried forward for
offset against future taxable profits.
USD'000
|
2023
|
|
2022
Restated*
|
|
|
|
|
(Loss)/Profit before
tax
|
(102,766)
|
|
63,193
|
Expected effective tax
rate
|
54%
|
|
56%
|
|
|
|
|
Tax at the country level effective
rate
|
(55,494)
|
|
35,388
|
|
|
|
|
Effect of different tax rates in
loss making jurisdictions
|
13,975
|
|
13,934
|
Malaysia PITA tax losses on
non-operated PSCs
|
10,060
|
|
8,742
|
Utilisation of PRRT
credits
|
17,795
|
|
(21,661)
|
PRRT tax refund
|
1,735
|
|
(1,121)
|
Capital gain tax from acquisition
of CWLH Assets
|
-
|
|
1,486
|
Australian decommissioning
levy
|
-
|
|
336
|
Non-deductible expenses
|
399
|
|
938
|
Deferred tax permanent
differences
|
2,155
|
|
9,217
|
PRRT permanent
differences
|
(4,269)
|
|
7,032
|
Adjustment in respect to prior
years
|
2,152
|
|
(335)
|
|
|
|
|
Tax (credit)/expense for the year
|
(11,492)
|
|
53,956
|
Australia taxes
The Australian corporate income
tax rate is 30% and PRRT is 40%, with the latter being cash based
and income tax deductible. The combined standard effective tax rate
is 58%, with the actual effective tax rate of 42% in 2023 (2022:
46%) being lower predominately due to the utilisation of PRRT
credits brought forward at Montara. Montara and the CWLH Assets
have approximately US$3.8 billion (2022: US$3.5 billion) and
US$493.4 million (2022: US$535.5 million) of unutilised PRRT
credits, respectively. Both assets are not expected to incur any
PRRT over their economic lives. There was an increase in the
deferred tax asset during 2023, resulting from income tax credits
as the trading losses are carried forward for offset against future
taxable profits.
Malaysia taxes
Malaysian PITA is a PSC based tax
on petroleum operations at the rate of 38%. There are no other
material taxes in Malaysia.
*Restatements explained in Note 50
of the Group's consolidated financial statements.
RECONCILIATION OF CASH
US$'000
|
2023
|
2022
Restated*
|
|
|
|
|
|
Cash and cash equivalents at the beginning of
year
|
|
123,329
|
|
117,865
|
Revenue
|
309,200
|
|
421,602
|
|
Other operating income
|
6,574
|
|
26,485
|
|
Production costs
|
(232,772)
|
|
(250,300)
|
|
Staff costs
|
(29,431)
|
|
(28,247)
|
|
General and administrative
expenses
|
(17,072)
|
|
(10,992)
|
|
Operating cash flows before movements in
working
capital
|
|
36,499
|
|
158,548
|
Movement in working
capital
|
|
6,837
|
|
36,819
|
Placement of decommissioning trust
fund for CWLH
Assets
|
|
(41,000)
|
|
(41,000)
|
Net tax paid
|
|
(14,461)
|
|
(33,130)
|
|
|
|
|
|
Investing activities
|
|
|
|
|
Purchases of intangible
exploration assets, oil and gas
properties, and plant and
equipment1
|
|
(109,524)
|
|
(82,628)
|
Cash paid on acquisition of
Sinphuhorm Assets
|
|
(27,853)
|
|
-
|
Dividends received from
associate
|
|
3,842
|
|
-
|
Cash received on acquisition of
CWLH Assets
|
|
-
|
|
5,750
|
Cash paid for acquisition of 10%
interest of Lemang
PSC
|
|
-
|
|
(500)
|
Other investing
activities
|
|
4,451
|
|
881
|
|
|
|
|
|
Financing activities
|
|
|
|
|
Net proceeds from issuance of
shares
|
|
50,964
|
|
784
|
Shares repurchased
|
|
(2,084)
|
|
(16,070)
|
Repayment of lease
liabilities
|
|
(14,400)
|
|
(13,914)
|
Total drawdown of
borrowings
|
|
232,000
|
|
-
|
Repayment of borrowings
|
|
(75,000)
|
|
-
|
Repayment of costs and interests
of borrowings
|
|
(13,260)
|
|
-
|
Other financing
activities
|
|
(6,936)
|
|
(860)
|
Dividends paid
|
|
-
|
|
(9,216)
|
|
|
|
|
|
Total cash and cash equivalent at the end of
year
|
|
153,404
|
|
123,329
|
*Restatements explained in Note 50
of the Group's consolidated financial statements.
1 Total capital
expenditure was US$115.9 million (2022: US$82.9 million),
comprising total capital expenditure paid of US$109.5 million
(2022: US$82.6 million), accrued capital expenditure of US$4.0
million (2022: US$0.3 million) and capitalisation of borrowing
costs of US$2.4 million (2022: nil).
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.
Adjusted opex/boe is based on
total production cost and incorporates lease payments linked to
operational activities, net of any income derived from those
right-of-use assets involved in production. The calculation
excludes factors such as oil inventories movement,
underlift/overlift adjustments, inventory write-downs, workovers,
and non-recurring repair and maintenance expenses, transportation
costs, supplementary payments associated with the PenMal Assets,
expenses related to non-operating assets, and DD&A. This
definition aims to ensure better comparability between
periods.
The adjusted production costs are
then divided by total produced barrels of oil equivalent for the
prevailing period to determine the unit operating cost per barrel
of oil equivalent.
USD'000 except where
indicated
|
|
2023
|
|
2022
Restated*
|
|
|
|
|
|
Production costs
(reported)
|
|
232,772
|
|
250,300
|
Adjustments
|
|
|
|
|
Lease payments related to
operating activity1
|
|
16,155
|
|
13,687
|
Underlift, overlift and crude
inventories movement2
|
|
9,297
|
|
(39,036)
|
Workover
costs3
|
|
(17,562)
|
|
(10,190)
|
Other
income4
|
|
(6,375)
|
|
(5,030)
|
Non-recurring operational
costs5
|
|
(19,654)
|
|
-
|
Non-recurring repair and
maintenance6
|
|
(1,773)
|
|
(13,761)
|
Transportation costs
|
|
(7,502)
|
|
(8,341)
|
PenMal Assets supplementary
payments and Australian royalties7
|
|
(16,056)
|
|
(26,381)
|
PenMal non-operated assets
operational costs8
|
|
(19,273)
|
|
(4,056)
|
|
|
|
|
|
Adjusted production costs
|
|
170,029
|
|
157,192
|
|
|
|
|
|
Total production (barrels of oil
equivalent)
|
|
4,566,060
|
|
4,192,618
|
|
|
|
|
|
Adjusted unit operating costs per barrel of oil
equivalent
|
|
37.24
|
|
37.49
|
1 Lease payments related to operating activities are lease
payments considered to be operating costs in nature, including
leased helicopters for transporting offshore crews. These lease
payments are added back to reflect the true cost of
production.
2 Underlift, overlift and crude inventories movement are added
back to the calculation to match the full cost of production with
the associated production volumes (i.e., numerator to match
denominator).
3 Workover costs are excluded to enhance comparability. The
frequency of workovers can vary significantly, across
periods.
4 Other income represents the rental income from a helicopter
rental contract (a right-of-use asset) to a third party.
5 Non-recurring operational costs mainly related to costs
incurred at Montara being interim tanker storage temporarily
employed as a result of the repair work relating to the storage
tanks of the 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.
6 Non-recurring repair and maintenance costs in 2023
predominately related to the repair of a
gas turbine generator at the PenMal Assets PM329
PSC. The costs during 2022 predominately
related to Montara Skua-11 repair works, gas compressor solar
engine change out and tank repairs following the shut-in of Montara
in August 2022.
7 The supplementary payments are required under the terms of
PSCs based on Jadestone's profit oil after entitlements. The
Australian royalties are related to local decommissioning cost
recovery levy plus royalties payable to the local state government
arising previously from the acquisition of the CWLH
Assets.
8 PenMal non-operated assets operational costs in 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 do not 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.
*Restatements explained in Note 50
of the Group's consolidated financial statements.
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:
USD'000
|
2023
|
|
2022
Restated*
|
|
|
|
|
Revenue
|
309,200
|
|
421,602
|
Production cost
|
(232,772)
|
|
(250,300)
|
Administrative staff
costs
|
(30,197)
|
|
(29,218)
|
Other expenses
|
(22,841)
|
|
(22,305)
|
Share of results of
associate
|
2,640
|
|
-
|
Other income, excluding interest
income
|
14,404
|
|
27,152
|
Other financial gains
|
-
|
|
1,904
|
|
|
|
|
Unadjusted EBITDAX
|
40,434
|
|
148,835
|
|
|
|
|
Non-recurring
|
|
|
|
Net loss from oil price and
foreign exchange derivatives
|
10,395
|
|
-
|
Non-recurring
opex1
|
40,700
|
|
20,534
|
Oil and gas properties written
off
|
3,067
|
|
-
|
Change in provision - Lemang PSC
contingent payments
|
(7,653)
|
|
7,333
|
Insurance claim
receipts2
|
-
|
|
(17,977)
|
Fair value loss on contingent
considerations
|
-
|
|
1,920
|
Others3
|
3,704
|
|
1,684
|
|
|
|
|
|
50,213
|
|
13,494
|
|
|
|
|
Adjusted EBITDAX
|
90,647
|
|
162,329
|
1 Non-recurring opex in 2023 includes PenMal Assets' PNLP
operational costs and Montara interim tanker storage costs which
was 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.
Non-recurring opex in 2023 also includes repair and maintenance
costs in 2023 predominately related to the repair of a gas turbine
generator at the PenMal Assets PM329 PSC. The costs in 2022
included one-off major maintenance/well intervention activities, in
particular the Montara Skua-11 repair
works, gas compressor solar engine change out and storage tank
repairs after the Montara production shut-in since mid-August 2022.
2 Represents proceeds of an insurance claim compensating for
the loss of production from the Montara Skua-11 well in 2020. The
2021 insurance claim proceeds related to a well control claim for the Montara Skua-11 well
workover.
3 Includes business development costs, external funding
sourcing costs, costs related to the termination of the Maari
acquisition and internal reorganisation costs.
*Restatements explained in Note 50
of the Group's consolidated financial statements.
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.
USD'000
|
2023
|
|
2022
|
|
|
|
|
Borrowings (principal
sum)
|
157,000
|
|
-
|
Cash and cash
equivalents
|
(153,404)
|
|
(123,329)
|
|
|
|
|
Net debt/(cash)
|
3,596
|
|
(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.
GLOSSARY
£
|
British pound sterling
|
2C
|
best estimate contingent
resource
|
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
|
bcf
|
billion cubic feet
|
boe
|
barrels of oil
equivalent
|
boe/d
|
barrels of oil equivalent per
day
|
bopd
|
barrels of oil 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
|
Interim Facility
|
a US$50 million debt facility
closed in February 2023
|
mscf
|
thousand standard cubic feet of
natural gas
|
mm
|
million
|
mmbbls
|
million barrels
|
mmboe
|
million barrels of oil
equivalent
|
mmcf/d
|
million standard cubic feet per
day
|
mmscf
|
million standard cubic
feet
|
MYR
|
Malaysian Ringgit
|
NOPSEMA
|
National Offshore Petroleum Safety
and Environmental Management Authority
|
NOPTA
|
National Offshore Petroleum Titles
Administrator
|
opex
|
operating expenditures
|
PETRONAS
|
Petroliam Nasional
Berhad
|
PITA
|
Petroleum Income Tax
|
PRRT
|
Petroleum Resource Rent
Tax
|
PSC
|
production sharing
contract
|
RBL
|
reserves based loan
|
reserves
|
hydrocarbon resource that is
anticipated to be commercially recovered from known accumulations
from a given date forward
|
resources
|
being quantities of hydrocarbons
which are estimated, on a given date, to be potentially recoverable
from known accumulations but which are not currently considered to
be commercially recoverable
|
Saudi CP
|
Saudi Aramco Contract
Price
|
US$ or USD
|
United States dollar
|
VIU
|
Value in use
|
The technical information in this
announcement has been prepared in accordance with the June 2018
Society of Petroleum Engineers, World Petroleum Congress, American
Association of Petroleum Geologists and Society of Petroleum
Evaluation Engineers Petroleum Resource Management System ("PRMS")
as the standard for classification and reporting.
A. Shahbaz Sikandar of Jadestone
Energy plc, Group Subsurface Manager with a Masters degree in
Petroleum Engineering, and who is a member of the Society of
Petroleum Engineers and has worked in the energy industry for more
than 25 years, has read and approved the technical disclosure in
this regulatory announcement.
The information contained within this announcement is
considered to be inside information prior to its release, as
defined in Article 7 of the Market Abuse Regulation No. 596/2014
which is part of UK law by virtue of the European Union
(Withdrawal) Act 2018, and is disclosed in accordance with the
Company's obligations under Article 17 of those
Regulations.
Consolidated Statement of Profit or Loss and Other
Comprehensive Income
for the year ended 31 December 2023
|
Notes
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
Consolidated statement of profit or loss
|
|
|
|
|
|
|
|
|
|
Continuing operations
|
|
|
|
|
|
|
|
|
|
Revenue
|
4 &
45
|
309,200
|
|
421,602
|
Production costs
|
5
|
(232,772)
|
|
(250,300)
|
Depletion, depreciation and
amortisation
|
6
|
(76,141)
|
|
(61,562)
|
Administrative staff
costs
|
7
|
(30,197)
|
|
(29,218)
|
Other expenses
|
10
|
(22,841)
|
|
(22,305)
|
Impairment of oil and gas
properties
|
12
|
(29,681)
|
|
(13,534)
|
Share of results of
associate
|
25
|
2,640
|
|
-
|
Other income
|
13
|
18,855
|
|
28,033
|
Finance costs
|
14
|
(41,829)
|
|
(11,427)
|
Other financial gains
|
15
|
-
|
|
1,904
|
|
|
|
|
|
(Loss)/Profit before tax
|
|
(102,766)
|
|
63,193
|
Income tax
credit/(expense)
|
16
|
11,492
|
|
(53,956)
|
|
|
|
|
|
(Loss)/Profit for the
year
|
|
(91,274)
|
|
9,237
|
|
|
|
|
|
(Loss)/Profit per ordinary
share
|
|
|
|
|
Basic and diluted (US$)
|
17
|
(0.18)
|
|
0.02
|
|
|
|
|
|
Consolidated statement of other comprehensive
income
|
|
|
|
|
|
|
|
|
|
(Loss)/Profit for the
year
|
|
(91,274)
|
|
9,237
|
|
|
|
|
|
Other comprehensive (loss)/income
|
|
|
|
|
|
|
|
|
|
Items that may be reclassified
subsequently to profit or loss:
|
|
|
|
|
Loss on unrealised cash flow
hedges
|
36
|
(30,509)
|
|
-
|
Hedging loss reclassified to
profit or loss
|
4 &
36
|
10,322
|
|
-
|
|
|
|
|
|
|
|
(20,187)
|
|
-
|
Tax credit relating to components
of other comprehensive loss
|
16
|
6,056
|
|
-
|
|
|
|
|
|
Other comprehensive
loss
|
|
(14,131)
|
|
-
|
|
|
|
|
|
Total comprehensive (loss)/income for the
year
|
|
(105,405)
|
|
9,237
|
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
All comprehensive income is
attributable to the equity holders of the parent.
Consolidated Statement of Financial Position as at 31
December 2023
|
Notes
|
|
31
December
2023
USD'000
|
|
31
December
2022
Restated*
USD'000
|
|
1 January
2022
Restated*
USD'000
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current assets
|
|
|
|
|
|
|
|
Intangible exploration
assets
|
21
|
|
79,564
|
|
77,928
|
|
93,241
|
Oil and gas properties
|
22
|
|
457,202
|
|
433,645
|
|
353,592
|
Plant and equipment
|
23
|
|
10,462
|
|
7,318
|
|
8,963
|
Right-of-use assets
|
24
|
|
31,099
|
|
8,193
|
|
13,852
|
Investment in associate
|
25
|
|
26,651
|
|
-
|
|
-
|
Other receivables and
prepayment
|
29
|
|
141,860
|
|
90,590
|
|
48,500
|
Deferred tax assets
|
27
|
|
26,774
|
|
22,843
|
|
23,866
|
Cash and cash
equivalents
|
30
|
|
1,008
|
|
676
|
|
852
|
|
|
|
|
|
|
|
|
Total non-current assets
|
|
|
774,620
|
|
641,193
|
|
542,866
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
|
|
Inventories
|
28
|
|
33,654
|
|
19,644
|
|
23,299
|
Trade and other
receivables
|
29
|
|
124,379
|
|
19,635
|
|
32,578
|
Tax recoverable
|
16
|
|
4,085
|
|
9,725
|
|
9,367
|
Cash and cash
equivalents
|
30
|
|
152,396
|
|
122,653
|
|
117,013
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
314,514
|
|
171,657
|
|
182,257
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
1,089,134
|
|
812,850
|
|
725,123
|
|
|
|
|
|
|
|
|
Equity and
liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital and reserves
|
|
|
|
|
|
|
|
Share capital
|
31
|
|
456
|
|
339
|
|
358
|
Share premium account
|
31
|
|
51,827
|
|
983
|
|
201
|
Merger reserve
|
33
|
|
146,270
|
|
146,270
|
|
146,270
|
Share-based payments
reserve
|
34
|
|
27,673
|
|
26,907
|
|
25,936
|
Capital redemption
reserve
|
35
|
|
24
|
|
21
|
|
-
|
Hedging reserve
|
36
|
|
(14,131)
|
|
-
|
|
-
|
Accumulated losses
|
|
|
(158,349)
|
|
(64,991)
|
|
(48,942)
|
|
|
|
|
|
|
|
|
Total equity
|
|
|
53,770
|
|
109,529
|
|
123,823
|
|
|
|
|
|
|
|
|
|
Notes
|
|
31
December
2023
USD'000
|
|
31
December
2022
Restated*
USD'000
|
|
1 January
2022
Restated*
USD'000
|
|
|
|
|
|
|
|
|
Non-current liabilities
|
|
|
|
|
|
|
|
Provisions
|
37
|
|
503,170
|
|
510,945
|
|
410,697
|
Borrowings
|
38
|
|
147,313
|
|
-
|
|
-
|
Lease liabilities
|
39
|
|
18,746
|
|
2,880
|
|
4,504
|
Other payables
|
41
|
|
16,966
|
|
-
|
|
-
|
Derivative financial
instruments
|
42
|
|
6,708
|
|
-
|
|
-
|
Deferred tax
liabilities
|
27
|
|
65,829
|
|
90,206
|
|
77,562
|
|
|
|
|
|
|
|
|
Total non-current liabilities
|
|
|
758,732
|
|
604,031
|
|
492,763
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
Borrowings
|
38
|
|
7,260
|
|
-
|
|
-
|
Lease liabilities
|
39
|
|
14,118
|
|
6,227
|
|
11,161
|
Trade and other
payables
|
41
|
|
113,979
|
|
73,352
|
|
70,107
|
Derivative financial
instruments
|
42
|
|
17,977
|
|
-
|
|
-
|
Warrants liability
|
43
XXXX
|
|
3,469
|
|
-
|
|
-
|
Provisions
|
37
|
|
108,525
|
|
703
|
|
930
|
Tax liabilities
|
|
|
11,304
|
|
19,008
|
|
26,339
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
276,632
|
|
99,290
|
|
108,537
|
|
|
|
|
|
|
|
|
Total liabilities
TOTAL EQUITY AND
LIABILITIES
|
|
|
1,035,364
|
|
703,321
|
|
601,300
|
|
|
|
|
|
|
|
|
Total equity and liabilities
|
|
|
1,089,134
|
|
812,850
|
|
725,123
|
*Certain 2022 and 2021 comparative
information has been restated and reclassified between line items.
Please refer to the affected notes to consolidated financial
statements and Note 50
Consolidated Statement of Cash Flows for the year ended 31
December 2023
|
Notes
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
|
Operating activities
|
|
|
|
|
|
(Loss)/Profit before tax
|
|
|
(102,766)
|
|
63,193
|
Adjustments for:
|
|
|
|
|
|
Depletion, depreciation and
amortisation
|
6
|
|
76,141
|
|
61,562
|
Finance costs
|
14
|
|
41,829
|
|
11,427
|
Impairment of oil and gas
properties
|
12
|
|
29,681
|
|
13,534
|
Assets written
off
|
10
|
|
5,114
|
|
212
|
Share-based
payments
|
7
|
|
766
|
|
971
|
Allowance for slow moving
inventories
|
10
|
|
655
|
|
3,768
|
(Reversal of)/Change in
provision
|
10 /
13
|
|
(7,653)
|
|
7,333
|
Interest income
|
13
|
|
(4,451)
|
|
(881)
|
Share of results of
associate
|
25
|
|
(2,640)
|
|
-
|
Unrealised foreign exchange
(gain)/loss
|
10 /
13
|
|
(177)
|
|
245
|
Accretion income on
Australian tax repayment plan
|
15
|
|
-
|
|
(1,904)
|
Reversal of impairment of
amount due from joint arrangement partner
|
13
|
|
-
|
|
(912)
|
|
|
|
|
|
|
Operating cash flows before movements in working
capital
|
|
|
36,499
|
|
158,548
|
|
|
|
|
|
|
(Increase)/Decrease in trade and
other receivables
|
|
|
(80,900)
|
|
519
|
Increase in inventories
|
|
|
(15,655)
|
|
(1,829)
|
Increase/(Decrease) in trade and
other payables
|
|
|
62,392
|
|
(2,871)
|
|
|
|
|
|
|
Cash generated from operations
|
|
|
2,336
|
|
154,367
|
|
|
|
|
|
|
Net tax paid
|
|
|
(14,461)
|
|
(33,130)
|
|
|
|
|
|
|
Net cash (used in)/generated from operating
activities
|
|
|
(12,125)
|
|
121,237
|
|
|
|
|
|
|
Investing activities
|
|
|
|
|
|
Cash paid for acquisition of
Sinphuhorm Assets
|
25
|
|
(27,853)
|
|
-
|
Cash received from acquisition of
CWLH Assets
|
19
|
|
-
|
|
5,750
|
Cash paid for acquisition of 10%
interest of Lemang PSC
|
20
|
|
-
|
|
(500)
|
Payment for oil and gas
properties
|
22
|
|
(107,500)
|
|
(78,938)
|
Payment for plant and
equipment
|
23
|
|
(516)
|
|
(356)
|
Payment for intangible exploration
assets
|
21
|
|
(1,508)
|
|
(3,334)
|
Dividends received from
associate
|
25
|
|
3,842
|
|
-
|
Interest received
|
13
|
|
4,451
|
|
881
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(129,084)
|
|
(76,497)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
|
Financing activities
|
|
|
|
|
|
Net proceeds from issuance of
shares
|
31
|
|
50,964
|
|
784
|
Shares repurchased
|
31
|
|
(2,084)
|
|
(16,070)
|
Dividends paid
|
32
|
|
-
|
|
(9,216)
|
Total drawdown of
borrowings
|
40
|
|
232,000
|
|
-
|
Repayment of borrowings
|
40
|
|
(75,000)
|
|
-
|
Interest on borrowings
paid
|
40
|
|
(5,007)
|
|
-
|
Borrowings costs paid
|
40
|
|
(7,595)
|
|
-
|
Commitment fees of borrowings
paid
|
40
|
|
(658)
|
|
-
|
Repayment of lease
liabilities
|
40
|
|
(14,400)
|
|
(13,914)
|
Interest on lease liabilities
paid
|
40
|
|
(2,771)
|
|
(769)
|
Other interest and fees
paid
|
|
|
(4,165)
|
|
(91)
|
|
|
|
|
|
|
Net cash generated from/(used in) financing
activities
|
|
|
171,284
|
|
(39,276)
|
|
|
|
|
|
|
Net increase in cash and cash equivalents
|
|
|
30,075
|
|
5,464
|
|
|
|
|
|
|
Cash and cash equivalents at
beginning of the year
|
|
|
123,329
|
|
117,865
|
|
|
|
|
|
|
Cash and cash equivalents at end of the
year
|
30
|
|
153,404
|
|
123,329
|
*Certain 2022 comparative
information has been restated and reclassified between line items.
Please refer to Note 50.
Notes to the Consolidated Financial Statements for the year
ended 31 December 2023
1. CORPORATE 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 and an associate (the
"Group"). These consolidated financial statements have been
prepared for the Jadestone Group and reflect the full financial
year ended 31 December 2023 in respect of the ultimate parent
company in accordance with IFRS (see Note 2).
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. ACCOUNTING POLICIES
BASIS OF PREPARATION
The financial statements have been
prepared in accordance with UK-adopted International Accounting
Standards and International Financial Reporting Standards ("IFRS")
as issued by the International Accounting Standards Board ("IASB")
and in conformity with the requirements of the Companies Act 2006
(the "Act").
The financial statements have been
prepared on the historical cost convention basis, except as
disclosed in the accounting policies below. Historical cost
is generally based on the fair value of the consideration given in
exchange for goods and services.
Fair value is the price that would
be received from selling an asset or paid to transfer a liability
in an orderly transaction between market participants at the
measurement date, regardless of whether that price is directly
observable or estimated using another valuation technique. In
estimating the fair value of an asset or a liability, the Group
takes into account the characteristics of the asset or liability
which market participants would take into account when pricing the
asset or liability at the measurement date. Fair value for
measurement and/or disclosure purposes in these consolidated
financial statements is determined on such a basis, except for
share-based payment transactions that are within the scope of IFRS
2 Share-based Payment,
leasing transactions that are within the scope of IFRS 16
Leases, and measurements
that have some similarities to fair value but are not fair value,
such as net realisable value in IAS 2 Inventories, or value in use in IAS 36
Impairment of
Assets.
In addition, for financial
reporting purposes, fair value adjustments are categorised into
level 1, 2 or 3, based on the degree to which the inputs to the
fair value adjustments are observable and the significance of the
inputs to the fair value measurement in its entirety, which are
described as follows:
-
Level 1 inputs are quoted prices (unadjusted) in
active markets for identical assets or liabilities that the Group
can access at the measurement date;
-
Level 2 inputs are inputs, other than quoted
prices included within Level 1, that are observable for the asset
or liability, either directly or indirectly; and
-
Level 3 inputs are unobservable inputs for the
asset or liability.
GOING CONCERN
The Directors are required to
assess the availability of financial resources to meet the Group's
financial liabilities for the foreseeable future, which for the
going concern assessment is the period up to 31 December 2025 (the
"Review Period").
As at 31 December 2023, the Group
had available liquidity of c.US$220.0 million, consisting of cash
and cash equivalents (excluding restricted cash) of US$144.2
million, undrawn RBL facility capacity of US$43.0 million and the
undrawn committed standby working capital facility of US$31.9
million (the "Working Capital Facility"), from Tyrus Capital Event
S.à.r.l ("Tyrus"), the Group's largest shareholder, which expires
on 31 December 2024
From the period 1 January 2024 to
31 March 2024, the Group's available unrestricted cash has ranged
from US$81.5 million to US$136.6 million, with a balance of
US$113.6 million as at 31 March 2024. Other than funding the
Group's planned operational and capital expenditures during the
first quarter of 2024, the Group also received a payment of US$35.3
million from the previous operator of the PNLP Assets for its share
of future well preservation activities and decommissioning costs
when it exited two PSCs during 2023, and made a net payment of
US$35.7 million for the acquisition of the second 16.67% interest
in the CWLH Assets, which comprised of a placement of US$42.0
million into the CWLH abandonment trust fund and a receipt of
US$6.3 million from the seller of the interest, reflecting the
accumulated economic benefits of the CWLH assets for the period
from the effective date of 1 July 2022 to completion.
The March 2024 RBL redetermination
has been finalised, setting a borrowing base of US$200.0 million
for the six-month period ending 30 September 2024. The
available borrowing base is projected at US$200.0 million and
US$169.2 million for the six-month periods ending 31 March 2025 and
30 September 2025, respectively.
The Group closely 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 latest cash and
liquidity forecasts reflect the outcome of the March 2024 RBL
redetermination and the availability of the Working Capital
Facility for the period up to 31 December 2024. This
represents a 'base case' which includes the Group's current
financial position and reflects the expected trading performance of
the Group's operations based on the current portfolio of assets,
excluding any future business/asset acquisitions.
The Group's forecasts and scenario
analyses are, among other factors, based on commodity prices per
the current forward curve taking into account the downside risks
and the associated impacts. Additionally, the Group's latest
liquidity forecasts include the ongoing hedging arrangements
entered into as required under the RBL facility.
Various risking scenarios, such as
lower oil prices (US$70/bbl flat nominal from July 2024 onwards),
unplanned downtime at Montara and CWLH Assets and a potential delay
to the Akatara project coming onstream have been modelled.
Where liquidity over the Review Period is reduced under these
scenarios, the Directors believe that several potential mitigating
factors exist in order to increase liquidity, including but not
limited to, i) an extension or refinancing of the Group's existing
working capital facility, ii) RBL capacity increases from capex
add-back or incremental hedging iii) shortening payment terms for
liftings from the Group's Australian assets, iv) prepayments for
the Group's oil sales and/or v) reducing or deferring the Group's
planned capital expenditure.
The Directors have assessed that,
based on the cash projections for the Review Period, the Group will
have sufficient liquidity in place throughout the Review Period,
and also after taking into consideration 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 Review
Period. Accordingly, they adopted the going concern basis in
preparing these audited consolidated financial
statements.
Adoption of new and revised standards
New and amended IFRS standards that are effective for the
current year
In the current year, the Group
adopted the following amendments that are effective from the
beginning of the year and is relevant to its operations. The
adoption of these amendments has not resulted in changes to the
Group's accounting policies, except as noted below.
Amendments to IAS 1 and
IFRS
Practice Statement
2
|
Disclosure of Accounting
Policies
|
Amendments to IAS 8
|
Definition of Accounting
Estimates
|
Amendments to IAS 12
|
International Tax Reform - Pillar
Two Model Rules
|
Amendments to IAS 12
|
Deferred Tax related to Assets and
Liabilities arising from a Single Transaction
|
Amendments to IFRS 4
|
Extension of the Temporary
Exemption from Applying IFRS 9
|
The Group's accounting policy has
been changed as a result of the adoption of the Amendments to IAS
12 Deferred Tax related to Assets
and Liabilities arising from a Single Transaction. The
amendments introduce a further exception from the initial
recognition exemption. Under the amendments, an entity does
not apply the initial recognition exemption for transactions that
give rise to equal taxable and deductible temporary differences.
Depending on the applicable tax law, equal taxable and
deductible temporary differences may arise on initial recognition
of an asset and liability in a transaction that is not a business
combination and affects neither accounting profit nor taxable
profit.
Following the amendments to IAS
12, an entity is required to recognise the related deferred tax
asset and liability, with the recognition of any deferred tax asset
being subject to the recoverability criteria in IAS 12. See
Note 50 for further details on the prior year restatements
resulting from the adoption of amendments to IAS 12.
New and revised IFRSs in issue but not yet
effective
At the date of authorisation of
these financial statements, the Group has not applied the following
amendments to IFRS standards relevant to the Group that have been
issued but are not yet effective:
Amendments to IAS 1
|
Classification of Liabilities as
Current or Non-current
|
Amendments to IAS
11
|
Classification of Liabilities as
Current or Non-current - Deferral of Effective Date
|
Amendments to IAS
11
|
Non-current Liabilities with
Covenants
|
Amendments to IAS 7 and IFRS
71
|
Supplier Finance
Arrangements
|
Amendments to IAS
212
|
Lack of exchangeability
|
Amendments to IFRS 16
|
Covid-19-Related Rent Concessions
beyond 30 June 2021
|
Amendments to IFRS
161
|
Lease Liability in a Sale and
Leaseback
|
The Directors of the Group
anticipate that the application of these amendments may have an
impact on the Group's consolidated financial statements in future
periods.
.
1 Effective from 1 January 2024.
2 To be announced by IASB.
BASIS OF CONSOLIDATION
The consolidated financial
statements incorporate the financial statements of the Company and
entities controlled by the Company and its subsidiaries made up to
31 December of each year. Control is achieved where the
Company:
-
Has power over the
investee;
-
Is exposed, or has rights, to variable returns
from its involvement with the investee; and
-
Has the ability to use its power to affect
its returns.
The Company reassesses whether or
not it controls an investee if facts and circumstances indicate
that there are changes to one or more of the three elements of
control listed above.
Consolidation of a subsidiary
begins when the Company obtains control over the subsidiary and
ceases when the Company loses control of the subsidiary.
Specifically, income and expenses of a subsidiary acquired or
disposed of during the year are included in the consolidated
statement of profit or loss and other comprehensive income from the
date the Company gains control until the date when the Company
ceases to control the subsidiary.
Profit or loss and each component
of other comprehensive income are attributed to the owners of the
Company. Total comprehensive income of subsidiaries is
attributed to the owners of the Company.
When necessary, adjustments are
made to the financial statements of subsidiaries to bring their
accounting policies into line with the Group's accounting
policies.
All intragroup assets and
liabilities, equity, income, expenses and cash flows relating to
transactions between members of the Group are eliminated in full on
consolidation.
BUSINESS COMBINATIONS
Acquisitions of businesses,
including joint operations which are assessed to be businesses, are
accounted for using the acquisition method. The consideration
for each acquisition is measured as the aggregate of the
acquisition date fair values of assets given, liabilities incurred
by the Company to the former owners of the acquiree, and equity
interests issued by the Company in exchange for control of the
acquiree. Acquisition-related costs are recognised in profit
or loss as incurred.
At the acquisition date, the
identifiable assets acquired and the liabilities assumed are
recognised at their fair value, except that:
-
Deferred tax assets or liabilities, and
liabilities or assets related to employee benefit arrangements are
recognised and measured in accordance with IAS 12 Income Taxes and IAS 19 Employee Benefits
respectively;
-
Liabilities or equity instruments related to
share-based payment transactions of the acquiree, or the
replacement of an acquiree's share-based payment awards
transactions with share-based payment awards transactions of the
acquirer, in accordance with the method in IFRS 2 Share-based Payment at the acquisition
date; and
-
Assets, or disposal groups, that are classified
as held for sale in accordance with IFRS 5 Non-Current Assets Held for Sale and
Discontinued Operations are measured in accordance with that
Standard.
Goodwill is measured as the excess
of the sum of the consideration transferred, the amount of any
non-controlling interests in the acquiree, and the fair value of
the acquirer's previously held equity interest in the acquiree (if
any) over the net of the acquisition-date amounts of the
identifiable assets acquired and the liabilities assumed. If,
after reassessment, the net of the acquisition-date amounts of the
identifiable assets acquired and liabilities assumed exceeds the
sum of the consideration transferred, the amount of any
non-controlling interests in the acquiree and the fair value of the
acquirer's previously held interest in the acquiree (if any), the
excess is recognised immediately in profit or loss as a bargain
purchase gain.
Where applicable, the
consideration for the acquisition includes any asset or liability
resulting from a contingent consideration arrangement, measured at
its acquisition date fair value. Subsequent changes in such
fair values are adjusted against the cost of acquisition where they
qualify as measurement period adjustments. Measurement period
adjustments are adjustments that arise from additional information
obtained during the 'measurement period' (which cannot exceed one
year from the acquisition date) about facts and circumstances that
existed at the acquisition date. The subsequent accounting
for changes in the fair value of the contingent consideration, that
do not qualify as measurement period adjustments, depends on how
the contingent consideration is classified.
Contingent consideration that is
classified as equity is not re-measured at subsequent reporting
dates and its subsequent settlement is accounted for within
equity. Contingent consideration that is classified as a
liability is remeasured at subsequent reporting dates with the
corresponding gain or loss being recognised in profit or
loss.
If the initial accounting for a
business combination is incomplete by the end of the reporting
period in which the combination occurs, the Group reports
provisional amounts for the items for which the accounting is
incomplete. Those provisional amounts are adjusted during the
measurement period (see below), or additional assets or liabilities
are recognised, to reflect new information obtained about facts and
circumstances that existed as of the acquisition date that, if
known, would have affected the amounts recognised as at that
date.
The measurement period is the
period from the date of acquisition to the date the Group obtains
complete information about facts and circumstances that existed as
at the acquisition date and is subject to a maximum of one year
from acquisition date.
Where an interest in a production
sharing contract ("PSC") is acquired by way of a corporate
acquisition, the interest in the PSC is treated as an asset
purchase unless the acquisition of the corporate vehicle meets the
definition of a business and the requirements to be treated as a
business combination.
ACCOUNTING FOR TRANSACTION THAT IS NOT A BUSINESS
COMBINATION
When a transaction or other event
does not meet the definition of a business combination due to the
asset or group of assets not meeting the definition of a business,
it is termed an 'asset acquisition'. In such circumstances,
the acquirer:
·
Identifies and recognises the individual
identifiable assets acquired (including those assets that meet the
definition of, and recognition criteria for, intangible assets
in IAS
38) and liabilities assumed;
and
·
Allocates the cost of acquiring the group of
assets and liabilities to the individual identifiable assets and
liabilities on the basis of their relative fair values at the date
of purchase.
Such a transaction or event does
not give rise to goodwill or a gain on a bargain
purchase.
Transaction costs in an asset
acquisition are generally capitalised as part of the cost of the
assets acquired in accordance with applicable standards.
FOREIGN CURRENCY TRANSACTIONS
The Group's consolidated financial
statements are presented in USD, which is the parent's functional
currency and presentation currency. The functional currencies
of subsidiaries are determined based on the economic environment in
which they operate.
In preparing the financial
statements of each individual Group entity, transactions in
currencies other than the entity's functional currency are recorded
at the rates of exchange prevailing on the dates of the
transactions. At the end of each reporting period, monetary
items denominated in foreign currencies are retranslated at the
rates prevailing at the end of the reporting period.
Non-monetary items carried at fair value that are denominated in
foreign currencies are retranslated at the rates prevailing on the
date when the fair value was determined. Non-monetary items
that are measured in terms of historical cost in a foreign currency
are not retranslated.
Exchange differences arising on
the settlement of monetary items, and on retranslation of monetary
items, are included in profit or loss for the period.
Exchange differences arising on
the retranslation of non-monetary items carried at fair value are
included in profit or loss for the period, except for differences
arising on the retranslation of non-monetary items in respect of
which gains or losses are recognised in other comprehensive
income. For such non-monetary items, any exchange component
of that gain or loss is also recognised in other comprehensive
income. There is no foreign currency translation reserve
created at the Group level as the functional currencies of all
subsidiaries are denominated in USD.
JOINT OPERATIONS
A joint operation is a joint
arrangement whereby the parties that have joint control of the
arrangement have rights to the assets, and obligations for the
liabilities, relating to the arrangement. Joint control is
the contractually agreed sharing of control of an arrangement,
which exists only when decisions about the relevant activities
require unanimous consent of the parties sharing
control.
When a Group entity undertakes its
activities under joint operations, the Group as a joint operator
recognises in relation to its interest in a joint
operation:
-
Its assets, including its share of any assets
held jointly;
-
Its liabilities, including its share of any
liabilities incurred jointly;
-
Its revenue from the sale of its share of the
output arising from the joint operation; and
-
Its expenses, including its share of any expenses
incurred jointly.
The Group accounts for the assets,
liabilities, revenue and expenses relating to its interest in a
joint operation in accordance with the IFRS standards applicable to
the particular assets, liabilities, revenues and
expenses.
When a Group entity transacts with
a joint operation in which a Group entity is a joint operator (such
as a sale or contribution of assets), the Group is considered to be
conducting the transaction with the other parties to the joint
operation, and gains and losses resulting from the transactions are
recognised in the Group's consolidated financial statements only to
the extent of other parties' interests in the joint
operation.
When a Group entity transacts with
a joint operation in which a Group entity is a joint operator (such
as a purchase of assets), the Group does not recognise its share of
the gains and losses until it resells those assets to a third
party.
Changes to the Group's interest in
a PSC usually require the approval of the appropriate regulatory
authority. A change in interest is recognised when:
-
Approval is considered highly likely;
and
-
All affected parties are effectively operating
under the revised arrangement.
Where this is not the case, no
change in interest is recognised and any funds received or paid are
included in the statement of financial position as contractual
deposits.
INVESMENT IN ASSOCIATES AND JOINT VENTURES
An associate is an entity over
which the group has significant influence and that is neither a
subsidiary nor an interest in a joint venture. Significant
influence is the power to participate in the financial and
operating policy decisions of the investee but is not control or
joint control over those policies.
A joint venture is a joint
arrangement whereby the parties that have joint control of the
arrangement have rights to the net assets of the joint arrangement.
Joint control is the contractually agreed sharing of control
of an arrangement, which exists only when decisions about the
relevant activities require unanimous consent of the parties
sharing control.
The results and assets and
liabilities of associates are incorporated in these financial
statements using the equity method of accounting.
Under the equity method, an
investment in an associate or a joint venture is recognised
initially in the consolidated statement of financial position at
cost and adjusted thereafter to recognise the Group's share of the
profit or loss and other comprehensive income of the associate.
When the Group's share of losses of an associate exceeds the
Group's interest in that associate (which includes any long-term
interests that, in substance, form part of the group's net
investment in the associate), the Group discontinues recognising
its share of further losses. Additional losses are recognised
only to the extent that the Group has incurred legal or
constructive obligations or made payments on behalf of the
associate.
An investment in an associate is
accounted for using the equity method from the date on which the
investee becomes an associate. On acquisition of the
investment in an associate, any excess of the cost of the
investment over the Group's share of the net fair value of the
identifiable assets and liabilities of the investee is recognised
as goodwill, which is included within the carrying amount of the
investment. Any excess of the Group's share of the net fair
value of the identifiable assets and liabilities over the cost of
the investment, after reassessment, is recognised immediately in
profit or loss in the period in which the investment is
acquired.
If there is objective evidence
that the Group's net investment in an associate is impaired, the
requirements of IAS 36 are applied to determine whether it is
necessary to recognise any impairment loss with respect to the
Group's investment. When necessary, the entire carrying
amount of the investment (including goodwill) is tested for
impairment in accordance with IAS 36 as a single asset by comparing
its recoverable amount (higher of value in use and fair value less
costs of disposal) with its carrying amount. Any impairment
loss recognised is not allocated to any asset, including goodwill
that forms part of the carrying amount of the investment. Any
reversal of that impairment loss is recognised in accordance with
IAS 36 to the extent that the recoverable amount of the investment
subsequently increases.
EXPLORATION AND EVALUATION COSTS
The costs of exploring for and
evaluating oil and gas properties, including the costs of acquiring
rights to explore, geological and geophysical studies, exploratory
drilling and directly related overheads such as directly
attributable employee remuneration, materials, fuel used, rig costs
and payments made to contractors are capitalised and classified as
intangible exploration assets ("E&E assets").
If no potentially commercial
hydrocarbons are discovered, the E&E assets are written off
through profit or loss as a dry hole. If extractable
hydrocarbons are found and, subject to further appraisal activity
(e.g., the drilling of additional wells), it is probable that they
can be commercially developed, the costs continue to be carried as
intangible exploration costs, while sufficient/continued progress
is made in assessing the commerciality of the
hydrocarbons.
Costs directly associated with
appraisal activity undertaken to determine the size,
characteristics and commercial potential of a reservoir following
the initial discovery of hydrocarbons, including the costs of
appraisal wells where hydrocarbons were not found, are initially
capitalised as E&E assets.
All such capitalised costs are
subject to technical, commercial and management review, as well as
review for indicators of impairment at the end of each reporting
period. This is to confirm the continued intent to develop or
otherwise extract value from the discovery. When such intent
no longer exists, or if there is a change in circumstances
signifying an adverse change in initial judgment, the costs are
written off.
When commercial reserves of
hydrocarbons are determined and development is approved by
management, the relevant expenditure is transferred to oil and gas
properties. The technical feasibility and commercial
viability of extracting a mineral resource is considered to be
determinable when proved or probable reserves are determined to
exist. The determination of proved or probable reserves is
dependent on reserve evaluations which are subject to significant
judgments and estimates.
Costs related to geological and
geophysical studies that relate to blocks that have not yet been
acquired, and costs related to blocks for which no commercially
viable hydrocarbons are expected, are taken direct to the profit or
loss and have been disclosed as exploration expenses.
OIL AND GAS PROPERTIES
Producing assets
The Group recognises oil and gas
properties at cost less accumulated depletion, depreciation and
impairment losses. Directly attributable costs incurred for
the drilling of development wells and for the construction of
production facilities are capitalised, together with the discounted
value of estimated future costs of decommissioning
obligations. Workover expenses are recognised in profit or
loss in the period in which they are incurred, unless it generates
additional reserves or prolongs the economic life of the well, in
which case it is capitalised. When components of oil and gas
properties are replaced, disposed of, or no longer in use, they are
derecognised.
Depletion and amortisation expense
Depletion of oil and gas
properties is calculated using the units of production method for
an asset or group of assets, from the date in which they are
available for use. The costs of those assets are depleted
based on proved and probable reserves.
Costs subject to depletion include
expenditures to date, together with approved estimated future
expenditure to be incurred in developing proved and probable
reserves. Costs of major development projects are excluded
from the costs subject to depletion until they are available for
use.
The impact of changes in estimated
reserves is dealt with prospectively by depleting the remaining
carrying value of the asset over the remaining expected future
production. If reserves estimates are revised downwards,
earnings could be affected by higher depletion expense, or an
immediate write-down of the property's carrying value.
Depletion amount calculated based
on production during the year is adjusted based on the net movement
of crude inventories at year end against beginning of the year,
i.e., depletion cost for crudes produced but not lifted are
capitalised as part of cost of inventories and recognised as
depletion expense when lifting occurs.
Asset restoration obligations
The Group estimates the future
removal and restoration costs of oil and gas production facilities,
wells, pipelines and related assets at the time of installation or
acquisition of the assets, and based on prevailing legal
requirements and industry practice. In most instances, the
removal of these assets will occur many years in the future.
The estimates of future removal costs are made considering relevant
legislation and industry practice and require management to make
judgments regarding the removal date, the extent of restoration
activities required, and future removal technologies.
Site restoration costs are
capitalised within the cost of the associated assets, and the
provision is stated in the statement of financial position at its
total estimated present value. These costs are based on
judgements and assumptions regarding removal dates, technologies,
and industry practice. This estimate is evaluated on a
periodic basis and any adjustment to the estimate is applied
prospectively. Changes in the estimated liability resulting
from revisions to estimated timing, amount of cash flows, or
changes in the discount rate are recognised as a change in the
asset restoration liability and related capitalised asset
restoration cost within oil and gas properties.
The Malaysian and Indonesian
regulators require upstream oil and gas companies to contribute to
an abandonment cess fund, including making periodic cess payments,
throughout the production life of the oil or gas field. The
Malaysian cess payment amount is assessed based on the estimated
future decommissioning expenditures on oil and gas facilities,
excluding wells. The Indonesian cess payment amount is
assessed based on the estimated future decommissioning expenditures
of all facilities. For operated licences, the cess payment
paid is classified as non-current receivables as the cess payment
paid is reclaimable by the Group in the future following the
commencement of decommissioning activities. For non-operated
licences, the cess payment paid reduces the asset restoration
liability.
An abandonment trust fund was set
up as part of the acquisition of the CWLH Assets to ensure there
are sufficient funds available for decommissioning activities at
the end of field life. The payment paid into the trust fund
is classified as non-current receivables as the amount is
reclaimable by the Group in the future following the commencement
of decommissioning activities.
The change in the net present
value of future obligations, due to the passage of time, is
expensed as an accretion expense within financing charges.
Actual restoration obligations settled during the period reduce the
decommissioning liability.
Capitalised asset restoration
costs are depleted using the units of production method (see above
accounting policy).
BORROWING COSTS
Borrowing costs are allocated to
periods over the term of the related debt, at a constant rate on
the carrying amount. Borrowings, as shown on the consolidated
statement of financial position, are net of arrangement fees and
issue costs, and the borrowing costs are amortised through to the
statement of profit or loss and other comprehensive income as
finance costs over the term of the debt.
Borrowing costs directly
attributable to the acquisition, construction or production of
qualifying assets, which are assets that necessarily take a
substantial period of time to get ready for their intended use or
sale, are added to the cost of those assets, until such time as the
assets are substantially ready for their intended use or
sale.
All other borrowing costs are
recognised in the profit or loss in the period in which they are
incurred.
Investment income earned on the
temporary investment of specific borrowings pending their
expenditure on qualifying assets is deducted from the borrowing
costs eligible for capitalisation. All other borrowing costs
are recognised in the statement of profit or loss in the period in
which they are incurred.
PLANT AND EQUIPMENT
Plant and equipment is stated at
cost less accumulated depreciation and any recognised impairment
loss.
Depreciation is charged so as to
write off the cost of assets evenly over their estimated useful
lives, on the following:
-
Computer equipment: 3 years; and
-
Fixtures and equipment: 3 years.
The estimated useful lives,
residual values and depreciation method are reviewed at each year
end, with the effect of any changes in estimate accounted for on a
prospective basis.
Materials and spares which are not
expected to be consumed within the next twelve months from the year
end are classified as plant and equipment.
Right-of-use assets are
depreciated over the shorter period of the lease term and the
useful life of the underlying asset. If the ownership of the
underlying asset in a lease is transferred, or the cost of the
right-of-use asset reflects that the Group expects to exercise a
purchase option, the related right-of-use asset is depreciated over
the useful life of the underlying asset.
An item of plant and equipment is
derecognised upon disposal or when no future economic benefits are
expected to arise from the continued use of asset. Any gain
or loss arising on the disposal or retirement of an item of plant
and equipment is determined as the difference between the sales
proceeds and the carrying amount of the asset and is recognised in
profit or loss.
IMPAIRMENT OF OIL AND GAS PROPERTIES, PLANT AND EQUIPMENT,
RIGHT-OF-USE ASSETS AND INTANGIBLE EXPLORATION
ASSETS
At the end of each reporting
period, the Group reviews the carrying amounts of its oil and gas
properties, plant and equipment, right-of-use assets and intangible
assets, excluding goodwill, to determine whether there is any
indication that those assets have suffered an impairment
loss. If any such indication exists, the recoverable amount
of the asset is estimated in order to determine the extent of the
impairment loss (if any). The impairment is determined on
each individual cash-generating unit basis (i.e., individual oil or
gas field or individual PSC). Where there is common
infrastructure that is not possible to measure the cash flows
separately for each oil or gas field or PSC, then the impairment is
determined based on the aggregate of the relevant oil or gas fields
or the combination of two or more PSCs. When a reasonable and
consistent basis of allocation can be identified, corporate assets
are also allocated to individual cash-generating units, or
otherwise they are allocated to the smallest group of
cash-generating units for which a reasonable and consistent
allocation basis can be identified.
Recoverable amount is the higher
of fair value less costs of disposal ("FVLCOD") and value in use
("VIU"). In assessing VIU, the estimated future cash flows
are discounted to their present value using a pre-tax discount rate
that reflects current market assessments of the time value of money
and the risks specific to the asset for which estimates of future
cash flows have not been adjusted. FVLCOD will be assessed on
a discounted cash flow basis where there is no readily available
market price for the asset or where there are no recent market
transactions.
If the recoverable amount of an
asset (or cash-generating unit) is estimated to be less than its
carrying amount, the carrying amount of the asset (or
cash-generating unit) is reduced to its recoverable amount.
An impairment loss is recognised immediately in profit or
loss.
Where an impairment loss
subsequently reverses, the carrying amount of the asset (or
cash-generating unit) is increased to the revised estimate of its
recoverable amount, but so that the increased carrying amount does
not exceed the carrying amount that would have been determined had
no impairment loss been recognised for the asset (or
cash-generating unit) in prior years. A reversal of an
impairment loss is recognised immediately in profit or
loss.
INVENTORIES
Inventories are valued at the
lower of cost and net realisable value. Cost is determined as
follows:
-
Petroleum products, comprising primarily of
extracted crude oil stored in tanks, pipeline systems and aboard
vessels, and natural gas, are valued using weighted average
costing, inclusive of depletion expense; and
-
Materials, which include drilling and maintenance
stocks, are valued at the weighted average cost
of acquisition.
Net realisable value represents
the estimated selling price in the ordinary course of business less
the estimated costs of completion and the estimated costs necessary
to make the sale. The Group uses its judgement to determine
which costs are necessary to make the sale considering its specific
facts and circumstances, including the nature of the
inventories. If the carrying value exceeds net realisable
value, a write-down is recognised. The write-down may be
reversed in a subsequent period if the inventory is still on hand,
but the circumstances which caused the write-down no longer to
exist.
Provision for slow moving
materials and spares are recognised in the "other expenses" (Note
10) line item in profit or loss as they are non-trade in
nature.
FINANCIAL INSTRUMENTS
Financial assets and financial
liabilities are recognised in the Group's consolidated statement of
financial position when the Group becomes a party to the
contractual provisions of the instrument.
Financial assets and financial
liabilities are initially measured at fair value. Transaction
costs that are directly attributable to the acquisition or issue of
the financial assets and financial liabilities (other than
financial assets and financial liabilities measured at fair value
through the profit or loss) are added to or deducted from the fair
value of the financial assets or financial liabilities, as
appropriate, on initial recognition.
Transaction costs directly
attributable to the acquisition of financial assets or financial
liabilities measured at fair value through profit or loss are
recognised immediately in profit or loss.
Financial assets
All financial assets are
recognised and derecognised on a trade date basis, where the
purchases or sales of financial assets is under a contract whose
terms require delivery of assets within the time frame established
by the market concerned.
All recognised financial assets
are measured subsequently in their entirety, at either amortised
cost or fair value, depending on the classification of the
financial assets.
Classification of financial
assets
Debt instruments that meet the
following conditions are measured subsequently at amortised
cost:
-
The financial asset is held within a business
model whose objective is to hold financial assets in order to
collect contractual cash flows; and
-
The contractual terms of the financial asset give
rise on specified dates to cash flows that are solely payments of
principal and interest on the principal amount
outstanding.
Debt instruments that meet the
following conditions are subsequently measured at fair value
through other comprehensive income ("FVTOCI"):
-
The financial asset is held within a business
model whose objective is achieved by both collecting contractual
cash flows and selling the financial assets; and
-
The contractual terms of the financial asset give
rise on specified dates to cash flows that are solely payments of
principal and interest on the principal amount
outstanding.
By default, all other financial
assets are subsequently measured at fair value through profit or
loss ("FVTPL").
Amortised cost and effective
interest method
The effective interest method is a
method of calculating the amortised cost of a financial asset and
of allocating interest income over the relevant period.
For financial assets, the
effective interest rate is the rate that exactly discounts
estimated future cash receipts (including all fees paid or received
that form an integral part of the effective interest rate,
transaction costs and other premiums or
discounts) excluding expected credit losses, through the expected life
of the financial asset, or, where appropriate, a shorter period, to
the gross carrying amount of the financial instrument on initial
recognition.
The amortised cost of a financial
asset is the amount at which the financial asset is measured at
initial recognition minus the principal repayments, plus the
cumulative amortisation using the effective interest method of any
difference between that initial amount and the maturity amount,
adjusted for any loss allowance. The gross carrying amount of
a financial asset is the amortised cost of a financial asset before
adjusting for any loss allowance.
Interest income is recognised
using the effective interest method for financial assets measured
subsequently at amortised cost and at fair value through other
comprehensive income. For financial assets other than
purchased or originated credit impaired financial assets, interest
income is calculated by applying the effective interest rate to the
gross carrying amount of a financial asset, except for financial
assets that have subsequently become credit impaired. For
financial assets that have subsequently become credit impaired,
interest income is recognised by applying the effective interest
rate to the amortised cost of the financial asset. If, in
subsequent reporting periods, the credit risk on the credit
impaired financial instrument improves so that the financial asset
is no longer credit impaired, interest income is recognised by
applying the effective interest rate to the gross carrying amount
of the financial asset.
Interest income is recognised in
profit or loss and is included in "other income" (Note 13) line
item.
Impairment of financial assets
The Group's financial assets that
are subject to the expected credit loss model comprise trade and
other receivables. While cash and bank balances are also
subject to the impairment requirements of IFRS 9 Financial Instruments, the expected
credit loss allowances are not expected to be significant due to
the banks having external credit ratings of 'investment grade' in
accordance with the globally understood definition.
The Group's trade and other
receivables are primarily with counterparties to oil and gas sales,
joint arrangement partners and non-trade related
parties.
The concentration of credit risk
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. Both customers have an A2
credit rating (Moody's).
All trade receivables are generally settled 30
days after the sale date. In the event that an invoice is
issued on a provisional basis then the final reconciliation is paid
within three days of the issuance of the final invoice, largely
mitigating any credit risk.
The Group recognises lifetime
expected credit loss ("ECL") for trade receivables. The
expected credit losses on these financial assets are estimated
based on days past due, applying expected non-recoveries for each
group of receivables.
The Group measures the loss
allowance for other receivables and amounts due from joint
arrangement partners at an amount equal to 12 months ECL, as there
is no significant increase in credit risk since initial
recognition.
Significant increase in credit risk
In assessing whether the credit
risk on a financial instrument has increased significantly since
initial recognition, the Group compares the risk of a default
occurring on the financial instrument as at the reporting date with
the risk of a default occurring on the financial instrument as at
the date of initial recognition. In making this assessment,
the Group considers both quantitative and qualitative information
that is reasonable and supportable, including historical experience
and forward looking information that is available without undue
cost or effort. Forward looking information considered
includes the future prospects of the industries in which the
Group's debtors operate, based on consideration of various external
sources of actual and forecast economic information plus
environment impacts that relate to the Group's core
operations.
In particular, the following
information is taken into account when assessing whether credit
risk has increased significantly since initial
recognition:
-
An actual or expected significant deterioration
in the financial instrument's external (if available), or internal
credit rating;
-
Significant deterioration in external market
indicators of credit risk for a particular financial instrument,
e.g., a significant increase in the credit spread, the credit
default swap prices for the debtor, or the length of time or the
extent to which the fair value of a financial asset has been less
than its amortised cost;
-
Existing or forecast adverse changes in business,
financial or economic conditions that are expected to cause a
significant decrease in the debtor's ability to meet its debt
obligations;
-
An actual or expected significant deterioration
in the operating results of the debtor;
-
Significant increases in credit risk on other
financial instruments of the same debtor; and
-
An actual or expected significant adverse change
in the regulatory, economic, or technological environment of the
debtor that results in a significant decrease in the debtor's
ability to meet its debt obligations.
Despite the foregoing, the Group
assumes that the credit risk on a financial instrument has not
increased significantly since initial recognition if the financial
instrument is determined to have low credit risk at the reporting
date. A financial instrument is determined to have low credit
risk if i) the financial instrument has a low risk of default, ii)
the borrower has a strong capacity to meet its contractual cash
flow obligations in the near term and iii) adverse changes in
economic and business conditions in the longer term may, but will
not necessarily, reduce the ability of the borrower to fulfil its
contractual cash flow obligations.
The Group regularly monitors the
effectiveness of the criteria used to identify whether there has
been a significant increase in credit risk and revises them, as
appropriate, to ensure that the criteria are capable of identifying
a significant increase in credit risk before the amount becomes
past due.
Definition of default
The Group considers the following
as constituting an event of default, for internal credit risk
management purposes, as historical experience indicates that
receivables that meet either of the following criteria are
generally not recoverable:
-
When there is a breach of financial covenants by
the counterparty; or
-
Information developed internally or obtained from
external sources indicates that the debtor is unlikely to pay its
creditors, including the Group, in full (without taking into
account any collateral held by the Group).
Credit-impaired financial assets
A financial asset is
credit-impaired when one or more events that have a detrimental
impact on the estimated future cash flows of that financial asset
have occurred. Evidence that a financial asset is
credit-impaired includes observable data about the following
events:
-
Significant financial difficulty of the issuer or
the borrower;
-
A breach of contract, such as a default or past
due event;
-
The lender(s) of the borrower, for economic or
contractual reasons relating to the borrower's financial
difficulty, having granted to the borrower a concession(s) that the
lender(s) would not otherwise consider;
-
It is becoming probable that the borrower will
enter bankruptcy or other financial reorganisation; or
-
The disappearance of an active market for that
financial asset because of financial difficulties.
Write-off policy
The Group writes off a financial
asset when there is information indicating that the counterparty is
in severe financial difficulty and there is no realistic prospect
of recovery, e.g., when the counterparty has been placed under
liquidation or has entered into bankruptcy proceedings, or in the
case of trade receivables, when the amounts are over one year past
due, whichever occurs sooner. Financial assets written off
may still be subject to enforcement activities under the Group's
recovery procedures, taking into account legal advice where
appropriate. Any recoveries made are recognised in profit or
loss.
Measurement and recognition of expected credit
losses
The measurement of ECL is a
function of the probability of default, loss given default (i.e.,
the magnitude of the loss if there is a default), and the exposure
at default. The assessment of the probability of default, and
loss given default, is based on historical data adjusted by forward
looking information as described above.
As for the exposure at default,
for financial assets, this is represented by the assets' gross
carrying amount at the reporting date, together with any additional
amounts expected to be drawn down in the future by the default date
determined based on historical trend, the Group's understanding of
the specific future financing needs of the debtors, and other
relevant forward looking information.
For financial assets, the expected
credit loss is estimated as the difference between all contractual
cash flows that are due to the Group in accordance with the
contract, and all the cash flows that the Group expects to receive,
discounted at the original effective interest rate.
If the Group has measured the loss
allowance for a financial instrument at an amount equal to lifetime
ECL in the previous reporting period, but determines at the current
reporting date that the conditions for lifetime ECL are no longer
met, the Group measures the loss allowance at an amount equal to 12
month ECL at the current reporting date, except for assets for
which the simplified approach was used.
Derecognition of financial assets
The Group derecognises a financial
asset only when the contractual rights to the cash flows from the
asset expire, or when it transfers the financial asset and
substantially all the risks and rewards of ownership of the asset
to another entity. If the Group neither transfers nor retains
substantially all the risks and rewards of ownership, and continues
to control the transferred asset, the Group recognises its retained
interest in the asset and an associated liability for amounts it
may have to pay. If the Group retains substantially all of
the risks and rewards of ownership of a transferred financial
asset, the Group continues to recognise the financial asset and
also recognises a collaterialised borrowing for the proceeds
received.
On derecognition of a financial
asset measured at amortised cost, the difference between the
asset's carrying amount and the sum of the consideration received
and receivables, is recognised in the profit or loss.
Financial liabilities
All financial liabilities are
measured subsequently at amortised cost, using the effective
interest method or at FVTPL.
However, financial liabilities
that arise when a transfer of a financial asset does not qualify
for derecognition, or when the continuing involvement approach
applies, are measured in accordance with the specific accounting
policies set out below.
Financial liabilities at
FVTPL
Financial liabilities are
classified as at FVTPL when the financial liability is (i)
contingent consideration of an acquirer in a business combination,
(ii) held for trading, or (iii) designated as at FVTPL.
A financial liability other than a
contingent consideration of an acquirer in a business combination
may be designated as at FVTPL upon initial recognition
if:
-
Such designation eliminates or significantly
reduces a measurement or recognition inconsistency that would
otherwise arise; or
-
The financial liability forms part of a group of
financial assets or financial liabilities or both, which is managed
and its performance is evaluated on a fair value basis, in
accordance with the Group's documented risk management or
investment strategy, and information about the grouping is provided
internally on that basis; or
-
It forms part of a contract containing one or
more embedded derivatives, and IFRS 9 permits the entire combined
contract to be designated as at FVTPL.
Financial liabilities classified
as at FVTPL are measured at fair value, with any gains or losses
arising on changes in fair value recognised in profit or loss to
the extent that they are not part of a designated hedging
relationship (see hedge accounting policy). The net gain or
loss recognised in profit or loss incorporates any interest paid on
the financial liability and is included in either "other financial
gains" (Note 15) or "finance costs" (Note 14) line item in profit
or loss.
Financial liabilities
measured subsequently at amortised cost
Other financial liabilities are
measured subsequently at amortised cost, using the effective
interest method.
The effective interest method is a
method of calculating the amortised cost of a financial liability
and of allocating interest expense over the relevant period.
The effective interest rate is the rate that exactly discounts
estimated future cash payments (including all fees paid or received
that form an integral part of the effective interest rate,
transaction costs and other premiums or discounts) through the
expected life of the financial liability, or (where appropriate) a
shorter period, to the amortised cost of a financial
liability.
Derecognition of financial liabilities
The Group derecognises financial
liabilities when, and only when, the Group's obligations are
discharged, cancelled or they expire. The difference between
the carrying amount of the financial liability derecognised, and
the consideration paid and payable, is recognised in profit or
loss.
Equity instruments
Ordinary shares issued by the
Company are classified as equity and recorded at the par value in
the share capital account and the fair value of the proceeds
received recorded in the share premium account.
Derivative financial instruments
The Group enters into a variety of
derivative financial instruments to manage its exposure to
commodity price and foreign exchange risks.
Derivatives are initially
recognised at fair value on the date the contract is entered into,
and are subsequently remeasured to fair value as at each reporting
date. The resulting gain or loss is recognised in profit or
loss immediately unless the derivative is designated and effective
as a hedging instrument, in which case the timing of the
recognition in profit or loss depends on the nature of the hedge
relationship.
A derivative with a positive fair
value is recognised as a financial asset whereas a derivative with
a negative fair value is recognised as a financial liability.
Derivatives are not offset in the financial statements unless the
Group has both a legally enforceable right and intention to
offset. A derivative is presented as a non-current asset or a
non-current liability if the remaining maturity of the instrument
is more than 12 months and it is not due to be realised or settled
within 12 months. Other derivatives are presented as current
assets or current liabilities.
Hedge accounting
All hedges are classified as cash
flow hedges, which hedges exposure to the variability in cash flows
that is either attributable to a particular risk associated with a
recognised asset or liability, or a component of a recognised asset
or liability, or a highly probable forecasted
transaction.
At the inception of the hedge
relationship, the Group documents the relationship between the
hedging instrument and the hedged item, along with its risk
management objectives and its strategy for undertaking various
hedge transactions. Furthermore, at the inception of the
hedge and on an ongoing basis, the Group documents whether the
hedging instrument is effective in offsetting changes in fair
values or cash flows of the hedged item attributable to the hedged
risk, which is when the hedging relationships meet all of the
following hedge effectiveness requirements:
-
there is an economic relationship between the hedged item and the
hedging instrument;
-
the effect of credit risk does not dominate the value changes that
result from that economic relationship; and
-
the hedge ratio of the hedging relationship is the same as that
resulting from the quantity of the hedged item that the Group
actually hedges and the quantity of the hedging instrument that the
Group actually uses to hedge that quantity of hedged
item.
If a hedging relationship ceases
to meet the hedge effectiveness requirement relating to the hedge
ratio, but the risk management objective for that designated
hedging relationship remains the same, the Group adjusts the hedge
ratio of the hedging relationship (i.e. rebalances the hedge), so
that it meets the qualifying criteria again.
The Group designates the full
change in the fair value of a forward contract (i.e. including the
forward elements) as the hedging instrument, for all of its hedging
relationships involving forward contracts. The Group
designates only the intrinsic value of option contracts as a hedged
item, i.e. excluding the time value of the option. The
changes in the fair value of the aligned time value of the option
are recognised in other comprehensive income and accumulated in the
cost of hedging reserve. If the hedged item is
transaction‑related, the time value is reclassified to profit or
loss when the hedged item affects profit or loss. If the hedged
item is time‑period related, then the amount accumulated in the
cost of hedging reserve is reclassified to profit or loss on a
rational basis; the Group applies straight‑line amortisation.
Those reclassified amounts are recognised in profit or loss in the
same line as the hedged item. If the hedged item is a
non‑financial item, then the amount accumulated in the cost of
hedging reserve is removed directly from equity and included in the
initial carrying amount of the recognised non‑financial item.
Furthermore, if the Group expects that some or all of the loss
accumulated in cost of hedging reserve will not be recovered in the
future, that amount is immediately reclassified to profit or
loss.
Note 42 sets out details of the
fair values of the derivative instruments used for hedging
purposes.
Movements in the hedging reserve
in equity are detailed in Note 36.
Cash flow hedges
The effective portion of changes
in the fair value of derivatives and other qualifying hedging
instruments that are designated and qualify as cash flow hedges is
recognised in other comprehensive income and accumulated under the
heading of cash flow hedging reserve, limited to the cumulative
change in fair value of the hedged item from inception of the
hedge. The gain or loss relating to the ineffective portion is
recognised immediately in profit or loss in either "other financial
gains" (Note 15) or "finance costs"
(Note 14) line item.
Amounts previously recognised in
other comprehensive income and accumulated in equity are
reclassified to profit or loss in the periods when the hedged item
affects profit or loss, in the same line as the recognised hedged
item. If the Group expects that some or all of the loss
accumulated in the cash flow hedging reserve will not be recovered
in the future, that amount is immediately reclassified to profit or
loss.
The Group discontinues hedge
accounting only when the hedging relationship (or a part thereof)
ceases to meet the qualifying criteria (after rebalancing, if
applicable). This includes instances when the hedging
instrument expires or is sold, terminated or exercised. The
discontinuation is accounted for prospectively. Any gain or loss
recognised in other comprehensive income and accumulated in cash
flow hedge reserve, at that time, remains in equity and is
reclassified to profit or loss when the forecast transaction
occurs. When a forecast transaction is no longer expected to
occur, the gain or loss accumulated in cash flow hedge reserve is
reclassified immediately to profit or loss.
FAIR VALUE ESTIMATION OF FINANCIAL ASSETS AND
LIABILITIES
The fair value of current
financial assets and liabilities carried at amortised cost,
approximate their carrying amounts, as the effect of discounting is
immaterial.
SHARE-BASED PAYMENTS
Share-based incentive arrangements
are provided to employees, allowing them to acquire shares of the
Company.
The fair value of equity-settled
options granted is recognised as an employee expense, with a
corresponding increase in equity.
Equity-settled share options are
valued at the date of grant using the Black-Scholes pricing model,
and are charged to operating costs over the vesting period of the
award. The charge is modified to take account of options
granted to employees who leave the Group during the vesting period
and forfeit their rights to the share options. In the case of
market-related performance conditions, the Group revises its
estimates of the number of equity instruments expected to vest at
the end of the reporting period. The impact of the revision
of the original estimates, if any, is recognised in profit or loss
such that the cumulative expense reflects the revised estimate,
with a corresponding adjustment to the share options
reserve.
Equity-settled share-based payment
transactions with parties other than employees are measured at the
fair value of goods or services received, except where that fair
value cannot be estimated reliably, in which case they are measured
at the fair value of the equity instruments granted, measured at
the date at which the entity obtains the goods or the counterparty
renders the service.
LEASES
The Group as lessee
The Group assesses whether a
contract is or contains a lease, at inception of the
contract. The Group recognises a right-of-use asset and a
corresponding lease liability with respect to all lease
arrangements in which it is the lessee, except for short-term
leases (defined as leases with a lease term of 12 months or less)
and leases of low value assets (such as personal computers, small
items of office furniture and telephones). For these leases, the
Group recognises the lease payments as an operating expense on a
straight-line basis over the term of the lease, unless another
systematic basis is more representative of the time pattern in
which economic benefits from the leased assets are
consumed.
The lease liability is initially
measured at the present value of the lease payments that are not
paid at the commencement date, discounted by using the rate
implicit in the lease. If this rate cannot be readily
determined, the lessee uses its estimated incremental borrowing
rate.
Lease payments included in the
measurement of the lease liability comprise fixed lease payments
(including in substance fixed payments).
The lease liability is presented
as a separate line in the consolidated statement of financial
position.
The lease liability is
subsequently measured by increasing the carrying amount to reflect
interest on the lease liability (using the effective interest
method), and by reducing the carrying amount to reflect the lease
payments made.
The Group remeasures the lease
liability (and makes a corresponding adjustment to the related
right-of-use asset) whenever:
-
The lease term has changed or there is a
significant event or change in circumstances resulting in a change
in the assessment of exercise of a purchase option, in which case
the lease liability is remeasured by discounting the revised lease
payments using a revised discount rate;
-
The lease payments change due to changes in an
index or rate or a change in expected payment under a guaranteed
residual value, in which case the lease liability is remeasured by
discounting the revised lease payments using an unchanged discount
rate (unless the lease payments change is due to a change in a
floating interest rate, in which case a revised discount rate is
used); or
-
A lease contract is modified and the lease
modification is not accounted for as a separate lease, in which
case the lease liability is remeasured based on the lease term of
the modified lease by discounting the revised lease payments using
a revised discount rate at the effective date of the
modification.
During the year, the Group did not
make any such adjustments.
The right-of-use assets comprise
the initial measurement of the corresponding lease liability, lease
payments made at or before the commencement day, less any lease
incentives received and any initial direct costs. They are
subsequently measured at cost less accumulated depreciation and
impairment losses.
Whenever the Group incurs an
obligation for costs to dismantle and remove a leased asset,
restore the site on which it is located, or restore the underlying
asset to the condition required by the terms and conditions of the
lease, a provision is recognised and measured under IAS 37.
To the extent that the costs relate to a right-of-use asset, the
costs are included in the related right-of-use asset, unless those
costs are incurred to produce inventories.
Right-of-use assets are
depreciated over the shorter period of the lease term and the
useful life of the underlying asset. If a lease transfers
ownership of the underlying asset, or the cost of the right-of-use
asset reflects that the Group expects to exercise a purchase
option, the related right-of-use asset is depreciated over the
useful life of the underlying asset. The depreciation starts
at the commencement date of the lease.
Right-of-use assets are presented
as a separate line in the consolidated statement of financial
position.
The Group applies IAS 36 to
determine whether a right-of-use asset is impaired and accounts for
any identified impairment loss as described in the "Impairment of
Assets" policy.
As a practical expedient, IFRS 16
permits a lessee not to separate non-lease components, and instead
account for any lease and associated non-lease components as a
single arrangement. The Group has not used this practical
expedient. For contracts that contain a lease component and
one or more additional lease or non-lease components, the Group
allocates the consideration in the contract to each lease component
on the basis of the relative stand-alone price of the lease
component and the aggregate standalone price of the non-lease
components.
PROVISIONS
Provisions are recognised when the
Group has a present obligation, legal or constructive, as a result
of a past event, and it is probable that the Group will be required
to settle the obligation, and a reliable estimate can be made of
the amount of the obligation.
The amount recognised as a
provision is the best estimate of the consideration required to
settle the present obligation at the end of the reporting period,
taking into account the risks and uncertainties surrounding the
obligation. Where a provision is measured using the cash
flows estimated to settle the present obligation, its carrying
amount is the present value of those cash flows, and where the
effect of the time value of money is material. The provisions
held by the Group are asset restoration obligations, contingent
payments, employee benefits and incentive scheme, as set out in
Note 37.
RETIREMENT BENEFIT OBLIGATIONS
Payments to defined contribution
retirement benefit plans are charged as an expense as and when
employees have tendered the services entitling them to the
contributions. Payments made to state managed retirement
benefit schemes, such as Malaysia's Employees Provident Fund, are
dealt with as payments to defined contribution plans where the
Group's obligations under the plans are equivalent to those arising
in a defined contribution retirement benefit plan. The Group
does not have any defined benefit plans.
REVENUE
Revenue from contracts with
customers is recognised in the profit or loss when performance
obligations are considered met, which is when control of the
hydrocarbons are transferred to the customer.
Revenue from the production of oil
and gas, in which the Group has an interest with other producers,
is recognised based on the Group's working interest and the terms
of the relevant production sharing contracts.
Liquids production revenue is
recognised when the Group gives up control of the unit of
production at the delivery point agreed under the terms of the sale
contract. This generally occurs when the product is
physically transferred into a vessel, pipe or other delivery
mechanism. The amount of production revenue recognised is
based on the agreed transaction price and volumes delivered.
In line with the aforementioned, revenue is recognised at a point
in time when deliveries of the liquids are transferred to
customers.
Gas production revenue is meter
measured based on the hydrocarbon volumes delivered. The
volumes delivered over a calendar month are invoiced based on
monthly meter readings. The price is either fixed (gas) or
linked to an agreed benchmark (high sulphur fuel oil) in
advance. This methodology is considered appropriate as it is
normal business practice under such arrangements. In line
with the aforementioned, revenue is recognised at a point in time
when deliveries of the gas are transferred to the
customer.
A receivable is recognised once
transfer has occurred, as this represents the point in time at
which the right to consideration becomes unconditional, and only
the passage of time is required before the payment is
due.
Under/Overlift
Offtake arrangements for oil and
gas produced in certain of the Group's jointly owned operations may
result in the Group not receiving and selling its precise share of
the overall production in a period. The resulting imbalance
between the Group's cumulative entitlement and share of cumulative
production less stock gives rise to an underlift or
overlift.
Entitlement imbalances in
under/overlift positions and the movements in inventory are
included in production costs (Note 5). An overlift liability
is measured on the basis of the cost of production and represents a
provision for production costs attributable to the volumes sold in
excess of entitlement. The underlift asset is measured at the
lower of cost and net realisable value, consistent with IAS 2, to
represent a right to additional physical inventory. A
underlift of production from a field is included in current
receivables and an overlift of production from a field is included
in current liabilities.
INCOME TAX
Income tax expense represents the
sum of the tax currently payable and deferred tax.
Current tax
The tax currently payable is based
on taxable profit or loss for the year. Taxable profit or
loss differs from profit or loss as reported in the statement of
profit or loss and other comprehensive income, because it excludes
items of income or expense that are taxable or deductible in other
years and it further excludes items that are not taxable or tax
deductible. The Group's liability for current tax is
calculated using tax rates (and tax laws) that have been enacted or
substantively enacted, in countries where the Company and its
subsidiaries operate, by the end of the reporting
period.
Petroleum resource rent tax (PRRT)
PRRT incurred in Australia is
considered for accounting purposes to be a tax based on
income. Accordingly, current and deferred PRRT expense is
measured and disclosed on the same basis as income tax.
PRRT is calculated at the rate of
40% of sales revenues less certain permitted deductions and is tax
deductible for income tax purposes. For Australian corporate
tax purposes, PRRT payment is treated as a deductible expense,
while PRRT refund is treated as an assessable income.
Therefore, for the purposes of calculating deferred tax, the
PRRT tax rate is combined with the Australian corporate tax rate of
30% to derive a combined effective tax rate of 28%.
Malaysia Petroleum Income Tax (PITA)
PITA incurred in Malaysia is
considered for accounting purposes to be a tax based on income
derived from petroleum operations. Accordingly, current and
deferred PITA expense is measured and disclosed on the same basis
as income tax.
PITA is calculated at the rate of
38% of sales revenues less certain permitted deductions and
deferred tax is calculated at the same rate.
Deferred tax
Deferred tax is recognised on
temporary differences between the carrying amounts of assets and
liabilities in the financial statements, and the corresponding tax
bases used in the computation of taxable profit. Deferred tax
liabilities are generally recognised for all taxable temporary
differences and deferred tax assets are recognised to the extent
that it is probable that taxable profits will be available, against
which deductible temporary differences can be utilised. Such
deferred tax assets and liabilities are not utilised if the
temporary difference arises from goodwill or from the initial
recognition (other than in a business combination) of other assets
and liabilities in a transaction that affects neither the taxable
profit nor the accounting profit.
Deferred tax liabilities are
recognised for taxable temporary differences arising on investments
in subsidiaries, except where the Group is able to control the
reversal of the temporary difference and it is probable that the
temporary difference will not reverse in the foreseeable
future.
Deferred tax assets arising from
deductible temporary differences associated with such investments
and interests, are only recognised to the extent that it is
probable that there will be sufficient taxable profits against
which to utilise the benefits of the temporary differences, and
they are expected to reverse in the foreseeable future.
The carrying amount of deferred
tax assets is reviewed at the end of each reporting period and
reduced to the extent that it is no longer probable that sufficient
taxable profits will be available to allow all or part of the asset
to be recovered.
Deferred tax is calculated at the
tax rates that are expected to apply in the period when the
liability is settled, or the asset realised, based on the tax rates
(and tax laws) that have been enacted or substantively enacted, by
the end of the reporting period. The measurement of deferred
tax liabilities and assets reflects the tax consequences that would
follow from the manner in which the Group expects, at the end of
the reporting period, to recover or settle the carrying amount of
its assets and liabilities.
Deferred tax assets and
liabilities are offset when there is a legally enforceable right to
set off current tax assets against current tax liabilities and when
they relate to income taxes levied by the same taxation authority
and the Group intends to settle its current tax assets and
liabilities on a net basis.
Current and deferred tax for the year
Current and deferred tax are
recognised as an expense or income in profit or loss, except when
they relate to items credited or debited outside profit or loss
(either in other comprehensive income or directly in equity), in
which case the tax is also recognised outside profit or loss
(either in other comprehensive income or directly in equity,
respectively).
Other taxes
Revenue, expenses, assets, and
liabilities are recognised net of the amount of goods and services
tax ("GST") or value added tax ("VAT") except:
-
When the GST/VAT incurred on a purchase of goods
and services is not recoverable from the taxation authority, in
which case the GST/VAT is recognised as part of the cost of
acquisition of the asset or as part of the expense item as
applicable; and
-
Receivables and payables, which are stated with
the amount of GST/VAT included.
The net amount of GST/VAT
recoverable from, or payable to, the taxation authority is included
as part of receivables or payables in the consolidated statement of
financial position.
CASH AND BANK BALANCES
Cash and bank balances comprise
cash in hand and at bank, and other short-term deposits held by the
Group with maturities of less than three months. Restricted
cash and cash equivalents balances are those which meet the
definition of cash and cash equivalents but are not available for
use by the Group.
3. CRITICAL ACCOUNTING JUDGEMENTS AND KEY SOURCES OF
ESTIMATION UNCERTAINTY
In the application of the Group's
accounting policies, Directors 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.
Critical accounting judgments
The following are the critical
judgements, apart from those involving estimates (see below) that
the Directors have made in the process of applying the Group's
accounting policies that have the most significant effect on the
amounts recognised in the financial statements.
a) Acquisitions, divestitures and/or
assignment of interests
The Group accounts for
acquisitions and divestitures by considering if the acquired or
transferred interest relates to that of an asset, or of a business
as defined in IFRS 3 Business
Combinations paragraph B7, B8 and Appendix A, in so far as
those principles do not conflict with the guidance in IFRS 11
Joint Arrangements
paragraph 21A. Accordingly, the Group considers if there is
the existence of business elements as defined in IFRS 3 (e.g.,
inputs and substantive processes), or a group of assets that
includes inputs and substantial processes that together
significantly contribute to the ability to create outputs and
providing a return to investors or other economic benefits.
The justifications for this assessment on the acquisition of the
CWLH Assets have been set out in Note 19.
b) Impairment of oil and gas
properties
The Group assesses each asset or
cash-generating unit ('CGU') (excluding goodwill, which is assessed
annually regardless of indicators) in each reporting period to
determine whether any indication of impairment exists.
Assessment of indicators of impairment or impairment reversal
and the determination of the appropriate grouping of assets into a
CGU or the appropriate grouping of CGUs for impairment purposes
require significant judgement. For example, individual oil
and gas properties may form separate CGUs whilst certain oil and
gas properties with shared infrastructure may be grouped together
to form a single CGU. Alternative groupings of assets or CGUs
may result in a different outcome from impairment testing.
See Note 12 for details on how these groupings have been determined
in relation to the impairment testing of oil and gas
properties.
c) Impairment of intangible
exploration assets
The Group takes into consideration
the technical feasibility and commercial viability of extracting a
mineral resource and whether there is any adverse information that
will affect the final investment decision. Additionally, the Group
performed recoverability assessment for the expenditures incurred
based on their cost recoverability in accordance to the terms of
the relevant production sharing contracts.
Key sources of estimation uncertainty
The key assumptions concerning the
future, and other key sources of estimation uncertainty at the end
of the reporting period, that have a significant risk of causing a
material adjustment to the carrying amounts of assets and
liabilities within the next financial year, are discussed
below.
a) Reserves
estimates
The Group's estimated reserves are
management assessments, and are independently assessed by an
independent third party, which involves reviewing various
assumptions, interpretations and assessments. These include
assumptions regarding commodity prices, exchange rates, future
production, transportation costs, climate related risks and
interpretations of geological and geophysical models to make
assessments of the quality of reservoirs and the anticipated
recoveries. Changes in reported reserves can impact asset
carrying amounts, the provision for restoration and the recognition
of deferred tax assets, due to changes in expected future cash
flows. Reserves are integral to the amount of depreciation,
depletion and amortisation charged to the statement of profit or
loss and other comprehensive income, and the calculation of
inventory. Based on the analysis performed, a 5% decrease in
the reserves estimates would result to a further impairment charge
of US$60.0 million and a 5% increase in the reserves estimates
would reduce the impairment charge by US$17.4 million.
The Directors consider 5% movements to the existing reserves a reasonable
assumption based on the historical technical adjustments during the
annual reserves assessment performed by an independent third party
and also in view of the mature assets that the Group owns with long
production history and therefore less volatility in reserves
estimates is anticipated.
b) Impairment of oil and gas properties and
intangible exploration assets
For the impairment assessment of
oil and gas properties, the Directors assess the recoverable
amounts using the VIU approach. The post-tax estimated future
cash flows are prepared based on estimated reserves, future
production profiles, future hydrocarbon price assumptions and
costs. The future hydrocarbon price assumptions used are
highly judgemental and may be subject to increased uncertainty
given climate change and the global energy transition. The
post-tax estimated future cash flows also included the carbon costs
estimates of each asset, where applicable. The inclusion of
carbon cost estimates of each asset is based on the Directors' best
estimate of any expected applicable carbon emission costs
payable. This requires Directors' best estimate of how future
changes to relevant carbon emission cost policies and/or
legislation are likely to affect the future cash flows of the
Group's applicable CGUs, whether enacted or not. Future
potential carbon cost estimates of each asset were included to the
extent the Directors have sufficient information to make such
estimates.
The Directors further take into consideration the impact of climate change
on estimated future commodity prices with the application of price
assumptions based on economic modelling in scenarios in which the
goals of the COP 21 Paris agreement are reached ("Paris aligned
price assumptions", see below).
The carrying amounts of intangible
exploration assets, oil and gas properties and right-of-use assets
are disclosed in Notes 21, 22 and 24, respectively.
The Group recognises that climate
change and the energy transition is likely to impact the demand for
oil and gas, thus affecting the future prices of these commodities
and the timing of decommissioning activities. This in turn
may affect the recoverable amount of the Group's oil and gas
properties and intangible exploration assets, and the carrying
amount of the ARO provision. The Group acknowledges that
there is a range of possible energy transition scenarios that may
indicate different outcomes for oil prices. There are
inherent limitations with scenario analysis and it is difficult to
predict which, if any, of the scenarios might eventuate.
The Group has assessed the
potential impacts of climate change and the transition to a lower
carbon economy in preparing the consolidated financial statements,
including the Group's current assumptions relating to demand for
oil and gas and their impact on the Group's long-term price
assumptions, and also taking into consideration the forecasted
long-term prices and demand for oil and gas under the Paris aligned
scenarios (IEA's NZE by 2050). The Group's current oil price
assumption for internal planning purposes is broadly in line with
the IEA's STEPS case, which in turn is underpinned by climate
policies and targets already announced by governments. The
Group has assessed the potential impacts of climate change and the
transition to a lower carbon economy in preparing the consolidated
financial statements. This is achieved by running the IEA's
NZE scenario through the Group's financial models and assessing the
impact on profitability, cash flow and asset values. The
IEA's NZE by 2050 case predicts global oil demand will fall from
US$97 mb/d in 2022 to US$78 mb/d by 2030 and US$24/mb/d by 2050.
Prices fall to US$40/bbl in 2030 and trend lower thereafter.
The oil price differential between STEPS and NZE becomes
significant from 2030 onwards. The Group monitors energy
transition risks and, through its annual risk reviews, challenges
its base case assumptions on a regular basis.
The
Directors will continue to review various global and regional
energy transition developments and their impacts on price
assumptions, including Paris aligned scenario price assumptions and
demand in line with the scenarios based on decrease to emissions as
the energy transition progresses and will continue to take these
into consideration in the future impairment assessments. See
further disclosures under the Sustainability Review section from
pages 13 to 29 in the Group Annual Report.
Sensitivity analyses
The Directors assess the impact of
a change in cash flows in impairment testing arising from a 10%
reduction in price assumptions used at year end, sourced from
independent third party, ERCE and approved by the Directors.
The forecasted price assumptions are US$78.5/bbl in 2024,
US$79.0/bbl in 2025, US$79.7/bbl in 2026, US$81.2/bbl in 2027 and
an average of US$89.8/bbl from 2028 onwards. The Directors
are of the view that these price assumptions are aligned with the
Group's latest internal forecasts, reflecting long-term views of
global supply and demand. The price assumptions used are
reviewed and approved by the Directors. Based on the analysis
performed, the Directors concluded that a 10% price reduction in
isolation under the various scenarios would result to a further
impairment charge of US$141.9 million and a 10% price increase in
isolation would reduce the impairment charge by US$17.4
million.
The oil price sensitivity analyses
above do not, however, represent the Directors' best estimate of any
impairments that might be recognised as they do not fully
incorporate consequential changes that may arise, such as
reductions in costs and changes to business plans, phasing of
development, levels of reserves and resources, and production
volumes. As an example, as price reduces, it is likely that
costs would decrease across the industry. The oil price
sensitivity analysis therefore does not reflect a linear
relationship between price and value that can be
extrapolated.
The Directors also tested the impact of a 5% (2022: 5%) change to the
post-tax discount rate used of 10.50% (2022: 10%) for impairment
testing of oil and gas properties, and concluded that a 5% increase
in the post-tax discount rate would result to a further impairment
charge of US$3.4 million and a 5% decrease in the post-tax discount
rate would reduce the impairment charge by US$3.5
million.
The Directors assessed the impact
of the change in cash flows used in impairment testing arising from
the application of the oil price assumptions under the Net Zero
Emissions by 2050 Scenario plus the inclusion of carbon cost
estimates as disclosed below. The oil prices under the Net
Zero Emissions by 2050 Scenario for each asset are as
follows:
|
2024
|
2025
|
2026
|
2027
|
2028
|
2029
onwards
|
|
US$/bbl
|
US$/bbl
|
US$/bbl
|
US$/bbl
|
US$/bbl
|
US$/bbl
|
|
|
|
|
|
|
|
Montara
|
81.6
|
77.3
|
75.6
|
69.0
|
62.4
|
51.3
|
Stag
|
81.6
|
77.3
|
75.6
|
69.0
|
62.4
|
49.3
|
CWLH Assets
|
81.6
|
77.3
|
75.6
|
69.0
|
62.4
|
49.8
|
PenMal Assets - PM323
PSC
|
81.6
|
77.3
|
75.6
|
69.0
|
62.4
|
-
|
PenMal Assets - PM329
PSC
|
81.6
|
77.3
|
75.6
|
69.0
|
62.4
|
51.3
|
Lemang PSC
|
81.6
|
77.3
|
75.6
|
69.0
|
62.4
|
49.3
|
Based on the analysis performed,
the reduction in operating cash flows under the Net Zero Emissions
by 2050 Scenario would result to a further impairment charge of
US$196.8 million to the Group's oil and gas properties. The
assumptions under the Net Zero Emissions by 2050 Scenario do not
reflect the existing market conditions and are dependent on various
factors in the future covering supply, demand, economic and
geopolitical events and therefore are inherently uncertain and
subject to significant volatility and hence unlikely to reflect the
future outcome.
c) Asset restoration
obligations
The Group estimates the future
removal and restoration costs of oil and gas production facilities,
wells, pipelines and related assets at the time of installation of
the assets and reviewed subsequently at the end of each reporting
period. In most instances the removal of these assets will
occur many years in the future.
The estimate of future removal
costs is made considering relevant legislation and industry
practice and requires the Directors
to make judgments regarding the removal date, the
extent of restoration activities required and future costs and
removal technologies.
The carrying amounts of the
Group's ARO is disclosed in Note 37 to the financial
statements.
Sensitivity analyses
Sensitivities have been run on the
discount rate assumption, with a 1% change being considered a
reasonable possible change for the purposes of sensitivity
analysis. A 1% reduction in discount rate would increase the
liability by US$46.0 million and a 1% increase in discount rate
would decrease the liability by US$41.3 million. A 1%
increase in the inflation rate would increase the liability by
US$46.3 million and a 1% decrease in inflation rate would decrease
the liability by US$42.3 million. A 10% increase in current
estimated costs would increase the liability by US$61.2 million and
a 10% decrease in current estimated costs would decrease the
liability by US$61.2 million. A one year deferral to the
estimated decommissioning year of each asset as disclosed in Note
37 would decrease the liability by US$30.8 million and an
acceleration of one year to the estimated decommissioning year as
disclosed in Note 37 would increase the liability by US$7.6
million. The Directors
consider the 1% movement to the discount rate and
inflation rate, 10% to the current estimated costs and one year
movement to the estimated decommissioning year a reasonable
assumption based on the historical adjustments to the risk-free
rates, base decommissioning costs and estimated decommissioning
year.
4. REVENUE
The Group presently derives its
revenue from contracts with customers for the sale of oil and gas
products.
In line with the revenue
accounting policies set out in Note 2, all revenue is recognised at
a point in time.
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Liquids revenue
|
|
317,469
|
|
418,483
|
Hedging loss (Note 36)
|
|
(10,322)
|
|
-
|
|
|
|
|
|
|
|
307,147
|
|
418,483
|
|
|
|
|
|
Gas revenue
|
|
2,053
|
|
3,119
|
|
|
|
|
|
|
|
309,200
|
|
421,602
|
As part of the RBL, during the
year, the Group entered into commodity
swap contracts to hedge approximately 50% of its forecasted planned
production from October 2023 to September 2025. The commodity swap
contracts were measured using hedge accounting. See Note 42
for the details of the commodity swap contracts.
5. PRODUCTION COSTS
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
Operating costs
|
|
114,779
|
|
100,664
|
Workovers
|
|
17,562
|
|
10,190
|
Logistics
|
|
34,109
|
|
31,895
|
Repairs and maintenance
|
|
55,572
|
|
60,174
|
Tariffs and transportation
costs
|
|
7,502
|
|
8,341
|
Decommissioning
expenses
|
|
12,545
|
|
-
|
Underlift, overlift and crude
inventories movement
|
|
(9,297)
|
|
39,036
|
|
|
|
|
|
|
|
232,772
|
|
250,300
|
Operating costs predominately
consists of offshore manpower costs of US$26.0 million (2022:
US$26.1 million), chemicals, services, supplies and other
production related costs for a total of US$49.3 million (2022:
US$38.3 million), Malaysian supplementary payments totalled US$10.1
million (2022: US$24.5 million), insurance of US$4.9 million (2022:
US$4.8 million) and non-operated assets production costs of US$16.0
million (2022: US$3.3 million). The Malaysian supplementary
payments are payable under the terms of PSCs based on the Group's
entitlement to profit from oil and gas. It is calculated at
70% of the excess revenue over the base price of the sale of oil as
set out under the terms of PSCs. These supplementary payments
are made to PETRONAS.
Underlift, overlift and crude
inventories movement resulted in a credit of US$9.3 million (2022:
US$39.0 million charge), mostly related to higher inventories on
hand at Montara and Stag at year end compared to beginning of the
year.
Workovers in 2023 and 2022 were
recurring in nature. The Group carried out a higher number of
workovers at Stag in comparison of 2022.
Repairs and maintenance in current
year include Montara storage tank repairs, FPSO maintenance and
fabric maintenance costs at both Montara and Stag. In 2022,
the costs included Montara Skua-11 repairment works, solar engine
change out and emergency tank repairs.
During the year, the previous
operator of the PenMal Assets' non-operated PSCs (the "PNLP
Assets") has completed the decommissioning works of the FPSO.
The decommissioning costs were partially funded by the cess
abandonment fund, with the remainder portion of US$12.5 million,
net to Jadestone, was funded by the Group's working capital and
expensed to profit or loss when incurred.
6. DEPLETION, DEPRECIATION AND AMORTISATION
("DD&A")
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
Depletion and amortisation (Note
22):
|
|
64,575
|
|
45,016
|
Depreciation of:
|
|
|
|
|
Plant and equipment (Note
23)
|
|
494
|
|
616
|
Right-of-use assets (Note
24)
|
|
15,251
|
|
13,015
|
Crude inventories
movement
|
|
(4,179)
|
|
2,915
|
|
|
|
|
|
|
|
76,141
|
|
61,562
|
The crude inventories movement
represents additional/reversal of depletion expense recognised
during the year based on the net movement of crude inventories at
year end against beginning of the year. For the purpose of the consolidated statement of cash flows,
this amount has been excluded from the movement in working
capital.
The depletion charge is calculated
based on units of production and adjusted based on the net movement
of crude inventories at year end against beginning of the
year. In 2023, the adjustment was for 211,261 bbls of crude
inventories at the end of 2023 compared to 90,681 bbls at the end
of 2022, mostly due to the restart of production at Montara since
March 2023, resulting in a total depletion credit of US$8.2
million.
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
7. ADMINISTRATIVE STAFF
COSTS
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Wages, salaries and
fees
|
|
24,729
|
|
24,825
|
Staff benefits in kind
|
|
4,702
|
|
3,422
|
Share-based
compensation
|
|
766
|
|
971
|
|
|
|
|
|
|
|
30,197
|
|
29,218
|
The compensations of Directors and
key management personnel are included in the above and disclosed
separately in Notes 9 and 48, respectively.
8. STAFF NUMBERS AND
COSTS
The average number of employees
(including Executive Directors) was:
|
|
2023
Number
|
|
2022
Number
|
|
|
|
|
|
Production
|
|
162
|
|
152
|
Technical
|
|
236
|
|
206
|
Administration
|
|
2
|
|
2
|
Management
|
|
9
|
|
9
|
|
|
|
|
|
|
|
409
|
|
369
|
Staff costs are split between
production costs (Note 5) for offshore personnel and administrative
staff costs (Note 7) for onshore personnel.
Their aggregate remuneration
comprised:
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Wages and salaries
|
|
47,940
|
|
45,548
|
Social security costs
|
|
212
|
|
199
|
Defined contribution pension
costs
|
|
3,655
|
|
3,573
|
Share-based
compensation
|
|
766
|
|
971
|
|
|
|
|
|
|
|
52,573
|
|
50,291
|
|
|
|
|
|
Contractors and consultants
costs
|
|
3,606
|
|
4,976
|
|
|
|
|
|
|
|
56,179
|
|
55,267
|
9. DIRECTORS' REMUNERATION AND
TRANSACTIONS
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Directors' remuneration
|
|
|
|
|
|
|
|
|
|
Salaries, fees, bonuses and
benefits in kind
|
|
2,496
|
|
2,805
|
Gains on exercise of
options
|
|
|
|
-
|
Amounts receivable under long term
incentive plans
|
|
300
|
|
341
|
Money purchase pension
contributions
|
|
102
|
|
78
|
|
|
|
|
|
|
|
2,898
|
|
3,224
|
|
|
|
|
|
Remuneration of the highest paid Director:
|
|
|
|
|
Salaries, fees, bonuses and
benefits in kind
|
|
1,028
|
|
1,236
|
Gains on exercise of
options
|
|
-
|
|
-
|
Amounts receivable under long term
incentive plans
|
|
210
|
|
271
|
Money purchase pension
contributions
|
|
65
|
|
65
|
|
|
|
|
|
|
|
1,303
|
|
1,572
|
|
|
|
|
|
|
|
Number
|
|
Number
|
|
|
|
|
|
The number of Directors who:
|
|
|
|
|
Are members of a defined benefit
pension scheme
|
|
-
|
|
-
|
Are members of a money purchase
pension scheme
|
|
2
|
|
2
|
Exercised options over shares in
the Company
|
|
-
|
|
-
|
Had awards receivable in the form
of shares under a long-term
incentive scheme
|
|
2
|
|
2
|
The Non-Executive Directors were
not granted any options/shares under the Company's long term
incentive plans.
10. OTHER
EXPENSES
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Corporate costs
|
|
14,179
|
|
10,405
|
Change in provision - Lemang PSC
contingent payments
|
|
-
|
|
7,333
|
Allowance for slow moving
inventories
|
|
655
|
|
3,768
|
Assets written off
|
|
5,114
|
|
212
|
Net foreign exchange
loss
|
|
1,728
|
|
442
|
Other expenses
|
|
1,165
|
|
145
|
|
|
|
|
|
|
|
22,841
|
|
22,305
|
Corporate costs include recurring
general and administration expenses such as professional fees,
office and travelling costs of US$10.5 million (2022: US$8.8
million) and non-recurring costs such as business development costs
of US$2.2 million (2022: US$0.8 million), professional fees in
relation to internal reorganisation of US$0.8 million (2022: US$0.1
million), equity fundraising of US$0.4 million (2022: nil) and
external funding sourcing of US$0.2 million (2022: US$0.2
million).
The change in provision in 2022
was associated with the Lemang PSC contingent payments represents
additional contingent payments related to the future Dated Brent
prices and Saudi CP prices during the first and second years of
production in the Lemang PSC. The provision for these
contingent payments were reversed in 2023 (Note 13).
Assets written off in 2023
represents the write off of Montara non-depletable oil and gas
properties of US$3.1 million following the cancellation of a
capital project for the preparation of Skua-12 well development and
written off of obsolete material and spares for US$2.0
million. In 2022, the Group has written off the office
equipment located in the New Zealand office following the
termination of the Maari acquisition in October
2022.
For the purpose of the
consolidated statement of cash flows, the net foreign exchange loss
reported above in 2022 included a net unrealised loss of US$0.2
million.
11. AUDITOR'S REMUNERATION
The analysis of the auditor's
remuneration is as follows:
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Fees payable to the Company's
auditor for the audit of the parent
company and Group's
consolidated financial statements
|
|
600
|
|
544
|
Audit fees of the
subsidiaries
|
|
417
|
|
390
|
|
|
|
|
|
|
|
1,017
|
|
934
|
No fee was paid to the Group's
auditor for non-audit services for either the Group or the Company
in 2022 or 2023.
The audit fee in prior year
represented the actual finalised fee agreed with the
auditor.
12. IMPAIRMENT OF ASSETS
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Impairment of oil and gas
properties (Note 22)
|
|
29,681
|
|
13,534
|
The impairment expense in 2023
consists of US$17.4 million for the impairment of Stag's oil and
gas properties, which is treated as a single cash-generating
unit. The impairment is made following the annual impairment
assessment performed by the Directors and identified that the VIU
of the operating asset, determined based on the post-tax discount
rate used of 10.50% (2022: FVLCOD approach was adopted, using
post-tax discount rate of 8.99%), is lower than the carrying
amount. The impairment was made to reduce the carrying amount
of Stag's oil and gas properties to its recoverable amount of
US$95.8 million. The key assumptions used in determining the
VIU are disclosed Note 3(b). The impairment is made in
relation to the producing asset of the Group located in Australia
as disclosed in Note 45.
Additionally, the Group also
provided impairment of US$12.3 million associated with the
adjustment to the ARO estimates for the PNLP Assets (Note 37) that
underwent retendering during the year after ceasing production in
2022, following the class suspension of the FPSO, as
disclosed on page 36 in the Group Annual Report. The revision
of ARO estimates reflects the change on assumptions used for the
estimation of the decommissioning costs.
In 2022, the impairment expense
was provided in full for the oil and gas properties of the PNLP
Asset, which are treated as a single cash-generating unit.
The impairment was made following the previous operator's decision
to shut in production after FPSO class suspension in February
2022. Accordingly, the VIU of the non-operated PSCs is valued
at nil as at the end of 2022.
The impairments for the PNLP
Assets in 2023 and 2022 were made in relation to the producing
asset of the Group located in Southeast Asia as disclosed in Note
45.
13. OTHER INCOME
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Interest income
|
|
4,451
|
|
881
|
Reversal of provisions - Lemang
PSC contingent payments
|
|
7,653
|
|
-
|
Net foreign exchange
gain
|
|
322
|
|
341
|
Insurance claims
|
|
-
|
|
17,977
|
Other income
|
|
6,429
|
|
8,834
|
|
|
|
|
|
|
|
18,855
|
|
28,033
|
Interest income consists of US$2.9
million (2022: US$0.1 million) generated from the CWLH Assets
abandonment trust fund and US$0.9 million (2022: nil) generated
from the Group's fixed term deposits. The abandonment trust
funds generates average interest rate of 4.5% (2022: 3.6%) and the
fixed term deposits generate average interest rate of 4.5% (2022:
nil).
The reversal of provisions
associated with the contingent payments for Lemang PSC in 2023
represents the derecognition of contingent payments associated with
the Saudi CP and Dated Brent prices due to the trigger events as
disclosed on Note 37 are not expected to occur based on the
specialist's consensus on Dated Brent prices and the historical
correlation between Dated Brent prices and Saudi CP.
Other income mainly consists of
rental income from a helicopter rental contract (a right-of-use
asset) to a third party of US$6.4 million (2022: US$5.0
million). The other income in 2022 also consisted of an
income of US$0.9 million related to amount recognised for
previously unrecognised amount due from a joint arrangement
partner.
In 2022, insurance claims were
made to compensate for loss of production following the
drilling of two wells at the Montara field wells in 2020.
These claims were resolved and the cash was received in Q4
2022.
For the purpose of the
consolidated statement of cash flows, the net foreign exchange gain
reported above in 2023 included a net unrealised gain of US$0.2
million (2022: nil).
14. FINANCE COSTS
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
Interest expense
|
|
2,710
|
|
5
|
Accretion expense for:
|
|
|
|
|
Asset restoration
obligations (Note 37)
|
|
20,201
|
|
8,333
|
RBL (Note 38)
|
|
5,517
|
|
-
|
Non-current Lemang PSC VAT
receivables
|
|
1,182
|
|
314
|
Interest expense on lease
liabilities
|
|
2,771
|
|
769
|
Warrants expense
|
|
3,469
|
|
-
|
Upfront fees on financing
facilities
|
|
2,656
|
|
-
|
Interest expense on financing
facilities
|
|
953
|
|
-
|
Changes in fair value
of:
|
|
|
|
|
Lemang PSC contingent
payments (Note 37)
|
|
868
|
|
349
|
CWLH Assets contingent
payment (Note 37)
|
|
60
|
|
-
|
PenMal Assets contingent
payment (Note 37)
|
|
-
|
|
1,571
|
RBL commitment fees
|
|
349
|
|
-
|
Fair value loss on derivative
liability (Note 42)
|
|
73
|
|
-
|
Other finance costs
|
|
1,020
|
|
86
|
|
|
|
|
|
|
|
41,829
|
|
11,427
|
The interest expense primarily
consists of US$1.3 million (2022: nil) from the US$50.0 million
debt facility ("Interim Facility") obtained and repaid during the
year and US$1.2 million (2022: nil) from the RBL facility (Note
38).
Warrants expense represents the
fair value of the warrant instrument entered into by the Group with
Tyrus Capital S.A.M. and funds managed by it, in June
2023.
The Group incurred upfront fees of
US$2.7 million (2022: nil) and interest of US$1.0 million (2022:
nil) in relation to the equity underwrite debt facility and
committed standby working capital facility executed with Tyrus
Capital Events S.a.r.l. during the year, see Notes 38 and 49 for
further details.
The changes in fair value of the
provision associated with the contingent payments for Lemang PSC of
US$0.9 million (2022: US$0.3 million) represents fair value
adjustments reflecting the effect of the time value of
money.
In 2022, the second contingent
payment arising from the acquisition of the PenMal Assets was
recognised in full for US$3.0 million as at 31 December 2022 (Note
37), resulted in an increase in the provision of US$1.6
million. The amount was recognised as an accrual as at 2022
year end, paid in January 2023.
Other finance costs includes
accretion expense of US$0.6 million (2022: nil) generated from an
Australian Tax Office ("ATO") repayment plan for corporate tax
payments. The repayment schedule is between September 2023 to
October 2024.
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
15. OTHER FINANCIAL GAINS
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Accretion income from Australian
tax repayment plan
|
|
-
|
|
1,904
|
Accretion income in 2022 was
generated from the ATO 2019 repayment plan due to early settlement
by the Group in May 2022.
16. INCOME TAX (CREDIT)/EXPENSE
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
Current tax
|
|
|
|
|
Corporate tax
(credit)/charge
|
|
(3,403)
|
|
15,656
|
Underprovision in prior
years
|
|
2,051
|
|
666
|
|
|
|
|
|
|
|
(1,352)
|
|
16,322
|
Australian petroleum resource rent
tax ("PRRT")
|
|
1,735
|
|
(1,121)
|
Malaysian petroleum income tax
("PITA")
|
|
10,377
|
|
11,899
|
|
|
|
|
|
|
|
10,760
|
|
27,100
|
|
|
|
|
|
Deferred tax
|
|
|
|
|
Corporate tax
|
|
(20,138)
|
|
14,087
|
PRRT
|
|
(4,269)
|
|
7,032
|
PITA
|
|
2,155
|
|
5,737
|
|
|
|
|
|
|
|
(22,252)
|
|
26,856
|
|
|
|
|
|
|
|
(11,492)
|
|
53,956
|
Jadestone Energy plc's tax
domicile is Singapore and is subjected to Singapore's domestic
corporate tax rate of 17%. Subsidiaries are resident for tax
purposes in the territories in which they operate.
The Australian corporate income
tax rate is applied at 30% of Australian corporate taxable
income. PRRT is calculated at 40% of sales revenue less
certain permitted deductions and is tax deductible for Australian
corporate income tax purposes.
As at year end, Montara and the
CWLH Assets have US$3.8 billion (2022: US$3.5 billion) and US$493.4
million (2022: US$535.5 million) of unutilised carried forward PRRT
credits, respectively. Based on Directors' latest forecasts,
the historic accumulated PRRT net losses are larger than cumulative
future expected PRRT taxable profits. Accordingly, Montara
and the CWLH Assets are not anticipated to incur any PRRT expense
in the future of the asset.
During the year, Stag recorded a
net PRRT credit of US$2.5 million (2022: US$5.9 million of PRRT
expense).
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
The Malaysian corporate income tax
is applied at 24% on non-petroleum taxable income. PITA is
calculated at 38% of sales revenue less certain permitted
deductions and is tax deductible for Malaysian corporate income tax
purposes.
PenMal Assets recorded PITA
expense of US$12.5 million during the year (2022: US$17.6
million).
The tax recoverable of US$4.1
million as at year end includes of a PITA receivable of US$3.3
million which arose from pre-economic effective date of the PenMal
Assets acquisition which will be payable to SapuraOMV following the
receipt of a tax refund. The Group has recognised the payable
to SapuraOMV as at year end.
The tax expense on the Group's
(loss)/profit differs from the amount that would arise using the
standard rate of income tax applicable in the countries of
operation as explained below:
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
(Loss)/Profit before tax
|
|
(102,750)
|
|
63,193
|
|
|
|
|
|
Tax calculated at the domestic tax
rates applicable to the profit/loss in the respective countries
(Australia 30%, Malaysia 24% & 38%, Canada 27% and Singapore
17%)
|
|
(27,543)
|
|
20,488
|
Effects of non-deductible
expenses
|
|
4,003
|
|
9,255
|
Effect of PRRT/PITA tax
expense
|
|
12,112
|
|
10,778
|
Deferred PRRT/PITA tax
(credit)/expense
|
|
(2,115)
|
|
12,769
|
Underprovision in prior
year
|
|
2,051
|
|
666
|
|
|
|
|
|
Tax (credit)/expense for the year
|
|
(11,492)
|
|
53,956
|
In addition to the amount charged
to the profit or loss, the following amounts relating to tax have
been recognised in other comprehensive income.
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Other comprehensive income - deferred tax
|
|
|
|
|
Income tax credit related to
carrying amount of hedged item
|
|
(6,056)
|
|
-
|
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
17. (LOSS)/PROFIT PER ORDINARY SHARE
The calculation of the basic and
diluted loss per share is based on the following data:
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
(Loss)/Profit for the purposes of
basic and diluted per share, being the net (loss)/profit for the
year attributable to equity holders of the Company
|
|
(91,258)
|
|
9,237
|
|
|
|
|
|
|
|
2023
Number
|
|
2022
Number
|
|
|
|
|
|
Weighted average number of
ordinary shares for the purposes of basic EPS
|
|
499,480,437
|
|
461,959,228
|
Effect of diluted potential
ordinary shares - share options
|
|
-
|
|
3,876,548
|
Effect of diluted potential
ordinary shares - performance shares
|
|
-
|
|
334,163
|
Effect of diluted potential
ordinary shares - restricted shares
|
|
-
|
|
202,823
|
|
|
|
|
|
Weighted average number of
ordinary shares for the purposes of dilutive EPS
|
|
499,480,437
|
|
466,372,762
|
In 2023, 2,493,421 of weighted
average potentially dilutive ordinary shares available for exercise
from in the money vested options, associated with share options
were excluded from the calculation of diluted EPS, as they are
anti-dilutive in view of the loss for the year.
In 2023, 79,326 of weighted
average contingently issuable shares associated under the Company's
performance share plan based on the respective performance measures
up to year end were excluded from the calculation of diluted EPS,
as they are anti-dilutive in view of the loss for the
year.
In 2023, 344,225 of weighted
average contingently issuable shares under the Company's restricted
share plan were excluded from the calculation of diluted EPS, as
they are anti-dilutive in view of the loss for the year.
In 2023, 17,095,890 of weighted
average contingently issuable shares under the Company's warrants
instrument were excluded from the calculation of diluted EPS, as
they are anti-dilutive in view of the loss for the year.
(Loss)/Profit per share (US$)
|
|
2023
|
|
2022
|
|
|
|
|
|
-
- Basic and diluted
|
|
(0.18)
|
|
0.02
|
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
18. ACQUISITION OF THE REMAINING 50% INTEREST IN THE
PNLP ASSETS
18.1 Effective Date and
Acquisition date
On 14 April 2023, Jadestone
assumed operatorship of the PNLP Assets following the decision of
the previous operator to withdraw from the licences. As part
of the takeover, the previous operator paid the Group a sum
representing its share of future wells preservation activities and
decommissioning costs. The effective date of the takeover is
14 April 2023.
18.2 Asset acquisition
The Directors have concluded that the acquisition of the remaining 50%
interest in the PNLP Assets is an asset acquisition as the PNLP
Assets does not come with an organised workforce due to the PNLP
Assets being shut-in since February 2022 as a result of the class
suspension of the Bunga Kertas FPSO which served the PNLP
Assets. Additionally, the Group does not take over any
process in the form of a system, protocol or standards to
contribute to the creation of outputs. Hence, the acquisition
does not fall within the definition of a business acquisition under
IFRS 3. The value of the assets acquired and liabilities
assumed in the acquisition of the remaining 50% interest in the
PNLP Assets were allocated on the basis of their relative fair
values at the date of acquisition based on sum received from the
previous operator.
18.3 Assets acquired and liabilities assumed at the date of
acquisition
The value of the identifiable
assets and liabilities, acquired and assumed as at the date of
acquisition, were allocated on the basis of their relative fair
values as follows:
|
USD'000
|
|
|
Asset
|
|
Non-current asset
|
|
Other receivables (Note
29)
|
28,176
|
|
|
|
28,176
|
|
|
Liability
|
|
Non-current liability
|
|
Provision for asset retirement
obligations (Note 37)
|
48,430
|
|
|
|
48,430
|
|
|
Net identifiable liability acquired
|
(20,254)
|
19. ACQUISITION OF INTEREST IN CWLH JOINT
OPERATION
19.1 Effective Date and
Acquisition Date
On 28 July 2022, the Group
executed a sale and purchase agreement ("SPA") with BP Developments
Australia Pty Ltd ("BP") to acquire BP's non-operated 16.67%
working interest in the Cossack, Wanaea, Lambert and Hermes oil
field development (the "North West Shelf Project" or "CWLH
Assets"), offshore Australia. The initial cash consideration
was US$20.0 million plus two contingent payments of US$2.0 million
each if the annual average Dated Brent price is equal to or above
US$50/bbl in 2022 and US$60/bbl in 2023. Both contingent
payment materialised and were paid in January 2023 and 2024,
respectively. The second contingent payment was recognised as
a payable at 2023 year end.
In addition to the total
consideration and as part of this transaction, the Group was
required to pay a total of US$82.0 million into a decommissioning
trust fund administered by the operator of the CWLH Assets.
The first tranche of US$41.0 million was paid immediately prior to
closing of the acquisition in November 2022 and two further
payments of US$20.5 million each were paid after approval by the
Offshore Petroleum & Greenhouse Gas Storage Act (2006) title
registration during 2023.
The acquisition completed on 1
November 2022. The acquisition has an economic effective date
of 1 January 2020, which meant the Group was entitled to net cash
generated since effective date to completion date, resulting in net
cash receipts of US$6.9 million at completion on 1 November
2022. On 17 May 2023, the Group received approval from the
National Offshore Petroleum Titles Administrator ("NOPTA") for the
title transfer.
The legal transfer of ownership
and control of the non-operated 16.67% working interest in the CWLH
Assets occurred on the date of completion, 1 November 2022 (the
"Acquisition Date"). Therefore, for the purpose of
calculating the purchase price allocation, the Directors have
assessed the fair value of the assets and liabilities associated
with the CWLH Assets as at the Acquisition Date.
On 14 November 2023, the Group
executed a sale and purchase agreement with Japan Australia LNG
(MIMI) Pty Ltd, to acquire additional interests of 16.67% in the
CWLH Assets. See Note 48 for further details.
19.2 Acquisition of a 16.67%
non-operated working interest
The CWLH Assets contain inputs
(working interest in the CWLH Assets) and processes (existing
organised workforce and onshore and offshore infrastructures
managed by the operator), which when combined has the ability to
contribute to the creation of outputs (oil). Accordingly, the
CWLH Assets constitute a business and as a consequence, we have
accounted for our acquisition of a 16.67% working interest in those
assets using the accounting principles of business combinations
accounting as set out in IFRS 3, and other IFRSs as required by the
guidance in IFRS 11 paragraph 21A.
A purchase price allocation
exercise was performed to identify, and measure at fair value, the
assets acquired and liabilities assumed in the business
combination. The consideration transferred was measured at
fair value. The Group has adopted the definition of fair
value under IFRS 13 Fair Value
Measurement to determine the fair values, by applying Level
3 of the fair value measurement hierarchy.
19.3 Fair
value of consideration
After taking into account various
adjustments the net consideration for the CWLH Assets resulted in a
cash receipt of US$6.9 million, as set out below:
|
USD'000
|
|
|
Asset purchase price
|
20,000
|
Closing statement
adjustments
|
(26,953)
|
|
|
Net cash receipts from the acquisition
|
(6,953)*
|
Fair value of purchase consideration
|
USD'000
|
|
|
Asset purchase price
|
20,000
|
Closing statement
adjustments
|
(26,953)
|
|
|
Net cash receipts from the acquisition
|
(6,953)*
|
Deferred contingent
consideration
|
3,940
|
|
|
Fair value of purchase consideration
|
(3,013)
|
* For the purpose of the
consolidated statement of cash flows, the Group received US$5.8
million from BP on the Acquisition Date, with the remaining US$1.2
million recognised as a receivable as at 2022 year end. This
cash amount was received in February 2023.
The Group considers that the
purchase consideration and the transaction terms to be reflective
of fair value for the following reasons:
· Open
and unrestricted market: there were no restrictions in place
preventing other potential buyers from negotiating with BP during
the sales process period and there were a number of other
interested parties in the formal sale process;
· Knowledgeable, willing and non-distressed parties: both the
Group and BP are experienced oil and gas operators under no duress
to buy or sell. The process was conducted over several months
which gave both parties sufficient time to conduct due diligence
and prepare analysis to support the transaction; and
· Arm's length nature: the Group is not a related party to
BP. Both parties had engaged their own professional
advisors. There is no reason to conclude that the transaction
was not transacted at arm's length.
19.4 Assets acquired and liabilities assumed at the date of
acquisition
During the year, the Group has
completed the purchase price assessment ("PPA") to determine the
fair values of the net assets acquired within 12 months from the
Acquisition Date. A PPA adjustment was made in relation to
the ARO provision and recognition of deferred tax asset associated
with the provision for asset restoration obligations following
additional information obtained subsequent to the acquisition of
the CWLH Assets. The adjusted fair values of the identifiable
assets and liabilities have been reflected in the consolidated
statement of financial position as at 31 December 2022.
Below are the effects of the final
PPA adjustments in accordance with IFRS 3:
|
Provisional
PPA
USD'000
|
|
Adjustments
USD'000
|
|
Final PPA
USD'000
|
|
|
|
|
|
|
Asset
|
|
|
|
|
|
Non-current asset
|
|
|
|
|
|
Oil and gas properties (Note
22)
|
41,976
|
|
(21,307)
|
|
20,669
|
Deferred tax assets
|
-
|
|
19,390
|
|
19,390
|
|
|
|
|
|
|
Current asset
|
|
|
|
|
|
Trade and other
receivables
|
27,870
|
|
-
|
|
27,870*
|
|
|
|
|
|
|
|
69,846
|
|
(1,917)
|
|
67,929
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
Non-current liabilities
|
|
|
|
|
|
Provision for asset restoration
obligations (Note 37)
|
60,158
|
|
4,475
|
|
64,633
|
Deferred tax
liabilities
|
12,593
|
|
(6,392)
|
|
6,201
|
|
|
|
|
|
|
Current liability
|
|
|
|
|
|
Trade and other
payables
|
108
|
|
-
|
|
108
|
|
|
|
|
|
|
|
72,859
|
|
(1,917)
|
|
70,942
|
|
|
|
|
|
|
Net identifiable liabilities assumed
|
(3,013)
|
|
-
|
|
(3,013)
|
* Trade and other receivables
consisted of a gross underlift position of 314,078 bbls acquired by
the Group, with a fair value of US$27.3 million, measured at the
prevailing market price of US$86.68/bbl. The underlift position was recognised as an expense following
a lifting which occurred in the middle of November 2022.
The balance also included a gross cash overcall
position owing by the operator of US$0.6 million as at the
acquisition date. The overcall position will be unwound in
the future based on the joint arrangement expenditures claim raised
by the operator. No loss allowances have been recognised in
respect to trade and other receivables.
Please refer to Note 50 for a
summary of the adjustment of comparative figures.
19.5 Impact of acquisition on the results of the Group
The Group's 2022 results included
US$56.6 million of revenue and US$9.3 million of after tax profit
attributable to the CWLH Assets.
Acquisition-related costs
amounting to US$0.5 million have been excluded from the
consideration transferred and have been recognised as an expense in
the prior year, within "other expenses" line item in the
consolidated statement of profit or loss and other comprehensive
income.
Had the business combination been
effected at 1 January 2022, and based on the performance of the
business during 2022 under BP, the Group would have generated
revenues of US$109.6 million and an estimated net profit after tax
of US$29.5 million.
20. ACQUISITION OF 10% INTEREST IN LEMANG
PSC
20.1 Acquisition date
On 23 November 2022, the
Group completed the acquisition of the
remaining 10% interest in the Lemang PSC. As a result,
Jadestone's interest (pre local government back-in rights) in the
Lemang PSC has increased to 100%.
The 10% interest was acquired
through the execution of a Settlement and Transfer Agreement
("STA") between the Group and PT Hexindo Gemilang Jaya
("Hexindo"). In return for the transfer of Hexindo's 10%
stake, the Group released Hexindo from unpaid amounts of US$1.4
million relating to Hexindo's interest in the Lemang PSC, which
consisted of US$0.4 million (Note 29) generated since 11 December
2020 when the Group first acquired the 90% working interest in the
Lemang PSC up to the STA date of 23 November 2021, plus US$1.0
million which arose prior to 11 December 2020. Additionally,
the Group paid a cash consideration of US$0.5 million (inclusive of
transfer taxes, which the Group has remitted directly to the
Indonesian government).
20.2 Assets acquired and liabilities assumed at the date of
acquisition
The assets and liabilities
associated with the 10% interest in the Lemang PSC, acquired and
assumed as at the date of acquisition, were:
|
USD'000
|
|
|
Asset
|
|
Non-current assets
|
|
Oil and gas properties (Note
22)
|
1,414
|
VAT receivables
|
1,338
|
|
|
Current assets
|
|
Trade and other
receivables
|
15
|
Inventories
|
26
|
|
|
|
2,793
|
|
|
Liabilities
|
|
Non-current liability
|
|
Provision for asset
restoration obligations
(Note 37)
|
337
|
|
|
Current liability
|
|
Trade and other
payables
|
598
|
|
|
|
935
|
|
|
Net identifiable assets acquired
|
1,858
|
The provision for ARO assumed by
the Group is associated with historical oil production by Mandala
Energy that ceased in 2016, prior to the acquisition of the 90%
operated interest by the Group in December 2020. The
obligation was assumed following the acquisition, and the
decommissioning expenditure is expected to be incurred from 2036,
at the end of the life of the planned gas development.
21. INTANGIBLE EXPLORATION ASSETS
|
USD'000
|
|
|
Cost
|
|
As at 1 January 2022
|
93,241
|
Additions
|
3,582(a)
|
Transfer
|
(18,895)
(b)
|
|
|
As at 31 December 2022
|
77,928
|
Additions
|
1,636(a)
|
|
|
As at 31 December 2023
|
79,564
|
|
|
Impairment
|
|
As at 1 January 2022 and 1 January 2023
|
-
|
Additions (Note 12)
|
-
|
|
|
As at 31 December 2023
|
-
|
|
|
Carrying amount
|
|
As at 1 January 2022
|
93,241
|
|
|
As at 31 December 2022
|
77,928
|
|
|
As at 31 December 2023
|
79,564
|
(a) For the purpose of the consolidated statement of cash flows,
current year expenditure on intangible exploration assets of US$0.1
million remained unpaid as at 31 December 2023 (2022: US$0.3
million).
(b) The transfer relates to the Lemang PSC in Indonesia. In
June 2022, the final investment decision was taken following
regulatory approval to award the engineering, procurement,
construction and installation ("EPCI") contract which established
commercial viability. The capitalised cost of US$18.9 million
was transferred to development assets as disclosed in Note
22.
22. OIL AND GAS
PROPERTIES
|
Production
assets
|
|
Development
assets
|
|
Total
|
|
USD'000
|
|
USD'000
|
|
USD'000
|
|
|
|
|
|
|
Cost
|
|
|
|
|
|
As at 1 January 2022
|
595,494
|
|
-
|
|
595,494
|
Changes in asset restoration
obligations (Note 37)
|
18,680
|
|
7
|
|
18,687
|
Acquisition of CWLH Assets (Note
19)
|
20,669
|
|
-
|
|
20,669
|
Acquisition of 10% interest in
Lemang PSC (Note 20)
|
-
|
|
1,414
|
|
1,414
|
Additions
|
62,319
|
|
16,619
|
|
78,938(a)
|
Written off
|
(3,704)
|
|
-
|
|
(3,704)(b)
|
Transfer
|
-
|
|
18,895
|
|
18,895
|
|
|
|
|
|
|
As at 31 December 2022 (Restated)*
|
693,458
|
|
36,935
|
|
730,393
|
Changes in asset restoration
obligations (Note 37)
|
7,150
|
|
-
|
|
7,150(a)
|
Additions
|
32,058
|
|
81,672
|
|
113,730(b)(e)
|
Transfer of 50% interest in PNLP
Assets
|
48,430
|
|
-
|
|
48,430(d)
|
Written off
|
(3,067)
|
|
-
|
|
(3,067)
|
|
|
|
|
|
|
As at 31 December 2023
|
778,029
|
|
118,607
|
|
896,636
|
|
|
|
|
|
|
Accumulated depletion, amortisation and
impairment
|
|
|
|
|
|
As at 1 January 2022
|
241,902
|
|
-
|
|
241,902
|
Charge for the year
|
45,016
|
|
-
|
|
45,016
|
Impairment
|
13,534
|
|
-
|
|
13,534
|
Written off
|
(3,704)
|
|
-
|
|
(3,704)(c)
|
|
|
|
|
|
|
As at 31 December 2022 (Restated)*
|
296,748
|
|
-
|
|
296,748
|
Charge for the year
|
64,575
|
|
-
|
|
64,575
|
Impairment
|
78,111
|
|
-
|
|
78,111(d)
|
|
|
|
|
|
|
As at 31 December 2023
|
439,434
|
|
-
|
|
439,434
|
|
|
|
|
|
|
Carrying amount
|
|
|
|
|
|
As at 1 January 2022
|
353,592
|
|
-
|
|
353,592
|
|
|
|
|
|
|
As at 31 December 2022
|
396,710
|
|
36,935
|
|
433,645
|
|
|
|
|
|
|
As at 31 December 2023
|
338,595
|
|
118,607
|
|
457,202
|
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
(a) The changes in ARO in Note 37 of US$19.4 million includes the
increase in ARO of the PNLP Assets of US$24.5 million while the
changes in ARO of US$7.2 million in this note includes the increase
in ARO of the PNLP Assets of US$12.3 million, being 50% of the
working interests owned by the Group. The remaining 50% for
the increase in ARO of the PNLP Assets of US$12.3 million is offset
against the non-current other payable (Note 41) due to the costs
are to be funded from the cash advances receivable from the
Malaysian joint arrangement partner for its share future
decommissioning costs on the PNLP Assets when it withdrew from the
licences in 2023.
(b) The additions in 2023 and 2022 represents cash paid for the
Group's capital expenditure projects. The additions in 2023
includes the capitalisation of borrowing costs of US$2.4
million.
(c) The written off amount in 2022 represented the fully
depreciated oil and gas properties associated with the Indonesian
Ogan Komering PSC of which the PSC had expired in 2018.
(d) 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 of US$48.4 million
following the transfer of operatorship, with a corresponding
increase to the oil and gas properties balance. The Directors
have assessed the recoverable amount of the oil and gas properties
acquired following the takeover to be zero using the VIU
approach. Accordingly, the oil and gas properties were fully
impaired and offset against the non-current other payable (Note 41)
for the reason as explained in (a) above, due to the uncertainty in
respect to a potential restart date for production under the PSCs
and as a result there is no certainty of future cash flows from the
oil and gas properties. On 31 October 2023, MPM1
invited Jadestone to participate in the bidding for the renamed
PNLP assets, which is now referred to as the "Puteri Cluster PSC,"
through Malaysia Bid Round Plus ("MBR+"). The Group submitted
its bid in January 2024, with results of the bidding anticipated in
May 2024. The Directors are reasonably confident that the bid
will be successful but there is no certainty of success and future
cash flows from the assets.
The remaining impairment amount
consists of the impairment of Stag's oil and gas properties for
US$17.4 million and PNLP Assets' oil and gas properties for US$12.3
million as further disclosed in Note 12.
(e) For the purpose of the consolidated statement of cash flows,
current year expenditure on oil and gas properties of US$3.8
million remained unpaid as at 31 December 2023 (2022:
nil).
1 Malaysia Petroleum Management ("MPM") is entrusted to act for
and on behalf of PETRONAS in the overall management of Malaysia's
petroleum resources.
23. PLANT AND EQUIPMENT
|
Computer
equipment
USD'000
|
|
Fixtures and
fittings
USD'000
|
|
Materials and
spares
USD'000
|
|
Total
USD'000
|
|
|
|
|
|
|
|
|
Cost
|
|
|
|
|
|
|
|
As at 1 January 2022
|
3,554
|
|
1,571
|
|
7,209
|
|
12,334
|
Additions
|
204
|
|
152
|
|
-
|
|
356
|
Written off
|
(313)
|
|
(14)
|
|
-
|
|
(327)
|
Transfer
|
-
|
|
-
|
|
(1,173)
|
|
(1,173)(a)
|
|
|
|
|
|
|
|
|
As at 31 December 2022
|
3,445
|
|
1,709
|
|
6,036
|
|
11,190
|
Additions
|
280
|
|
236
|
|
-
|
|
516
|
Transfer
|
-
|
|
-
|
|
3,122
|
|
3,122(a)
|
|
|
|
|
|
|
|
|
As at 31 December 2023
|
3,725
|
|
1,945
|
|
9,158
|
|
14,828
|
|
|
|
|
|
|
|
|
Accumulated depreciation
|
|
|
|
|
|
|
|
As at 1 January 2022
|
1,959
|
|
1,412
|
|
-
|
|
3,371
|
Charge for the year
|
450
|
|
166
|
|
-
|
|
616
|
Written off
|
(101)
|
|
(14)
|
|
-
|
|
(115)
|
|
|
|
|
|
|
|
|
As at 31 December 2022
|
2,308
|
|
1,564
|
|
-
|
|
3,872
|
Charge for the year
|
347
|
|
147
|
|
-
|
|
494
|
|
|
|
|
|
|
|
|
As at 31 December 2023
|
2,655
|
|
1,711
|
|
-
|
|
4,366
|
|
|
|
|
|
|
|
|
Carrying amount
|
|
|
|
|
|
|
|
As at 1 January 2022
|
1,595
|
|
159
|
|
7,209
|
|
8,963
|
|
|
|
|
|
|
|
|
As at 31 December 2022
|
1,137
|
|
145
|
|
6,036
|
|
7,318
|
|
|
|
|
|
|
|
|
As at 31 December 2023
|
1,070
|
|
235
|
|
9,158
|
|
10,462
|
(a) The transfer represents the material and spares that are not
expected to be consumed within the next 12 months from the year
end. The reclassification amount is net of allowance of slow
moving items of US$1.7 million (2022: US$2.7 million).
24. RIGHT-OF-USE ASSETS
|
Transportation and
logistics
USD'000
|
|
Buildings
USD'000
|
|
Total
USD'000
|
|
|
|
|
|
|
Cost
|
|
|
|
|
|
As at 1 January 2022
|
43,545
|
|
4,823
|
|
48,368
|
Additions
|
6,701
|
|
655
|
|
7,356
|
Written off*
|
(4,146)
|
|
(1,835)
|
|
(5,981)
|
|
|
|
|
|
|
As at 31 December 2022
|
46,100
|
|
3,643
|
|
49,743
|
Additions
|
36,926
|
|
1,231
|
|
38,157
|
Written off*
|
(39,673)
|
|
-
|
|
(39,673)
|
|
|
|
|
|
|
As at 31 December 2023
|
43,353
|
|
4,874
|
|
48,227
|
|
|
|
|
|
|
Accumulated depreciation
|
|
|
|
|
|
As at 1 January 2022
|
31,408
|
|
3,108
|
|
34,516
|
Charge for the year
|
12,224
|
|
791
|
|
13,015
|
Written off*
|
(4,146)
|
|
(1,835)
|
|
(5,981)
|
|
|
|
|
|
|
As at 31 December 2022
|
39,486
|
|
2,064
|
|
41,550
|
Charge for the year
|
14,390
|
|
861
|
|
15,251
|
Written off*
|
(39,673)
|
|
-
|
|
(39,673)
|
|
|
|
|
|
|
As at 31 December 2023
|
14,203
|
|
2,925
|
|
17,128
|
|
|
|
|
|
|
Carrying amount
|
|
|
|
|
|
As at 1 January 2022
|
12,137
|
|
1,707
|
|
13,852
|
|
|
|
|
|
|
As at 31 December 2022
|
6,614
|
|
1,579
|
|
8,193
|
|
|
|
|
|
|
As at 31 December 2023
|
29,150
|
|
1,948
|
|
31,099
|
* This represents the write off of
expired leases.
Most of the Group's right-of-use
assets are contracts to lease assets including helicopters, a
supply boat, logistic facilities for the Montara field and
buildings. The average lease term is 2.7 years. The
additions to right-of-use assets during the year mainly consist of
the extension of the Group's helicopter lease and Montara warehouse
lease for three years and two years, respectively, plus a two-year
lease for Montara vessel to replace an expired lease.
The maturity analysis of lease
liabilities is presented in Note 39.
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
Amount recognised in profit or loss
|
|
|
|
Depreciation expense on
right-of-use assets
|
15,251
|
|
13,015
|
Interest expense on lease
liabilities
|
2,771
|
|
769
|
Expenses relating to short-term
leases
|
36,680
|
|
16,028
|
Expense relating to leases of low
value assets
|
44
|
|
68
|
As at 31 December 2023, the Group
is committed to US$3.9 million of short-term leases (2022: US$3.0
million).
The total cash outflow in 2023
relating to leases was US$53.9 million (2022: US$30.8
million).
25. INVESTMENT IN ASSOCIATE
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
At beginning of year
|
|
-
|
|
-
|
|
|
|
|
|
Acquisition of 9.52% non-operated
interest in Sinphuhorm Assets
|
|
27,853
|
|
-
|
Dividends received during the
year
|
|
(3,842)
|
|
|
Share of profit of the
associate
|
|
2,640
|
|
|
|
|
|
|
|
At end of year
|
|
26,651
|
|
-
|
On 19 January 2023, the Group
executed a sale and purchase agreement with Salamander Energy (S.E.
Asia) Limited, an affiliate of PT Medco Energi Internasional Tbk,
to acquire its interest in three legal entities, which collectively
own a 9.52% non-operated interest in the producing Sinphuhorm gas
field and a 27.2% interest in the Dong Mun gas discovery onshore
north-east Thailand. The acquisition included a 27.2%
interest in APICO LLC, which operates the Sinphuhorm concessions
(E5N and EU1) and Dong Mun (L27/43). The acquisition was
completed on 23 February 2023, for a cash consideration of US$27.9
million. The acquisition has an economic effective date of 1
January 2022, which meant the Group was entitled to net cash
generated since effective date to completion date.
APICO LLC is limited liability
company incorporated in the State of Delaware, United States of
America. Its primary business purpose is the acquisition,
exploration, development and production of petroleum interests in
the Kingdom of Thailand. Its principal activities are
currently exploration in operated concessions and gas production in
non-operated concessions.
The Group has applied equity
accounting for the investment in associate. The summarised
financial information in respect of the associate, APICO LLC, since
the date of acquisition of 23 February 2023 is set out below.
The summarised financial information below represents amounts in
associates' financial statements which holds a 35% interest in the
Sinphuhorm gas field. The APICO LLC's financial statements
are prepared in accordance with IFRS Accounting
Standards.
|
|
2023
USD'000
|
|
|
|
Current assets
|
|
39,027
|
Non-current assets
|
|
133,037
|
Current liabilities
|
|
27,048
|
Non-current liabilities
|
|
6,902
|
|
|
|
Revenue
|
|
59,504
|
Profit before tax
|
|
26,412
|
Profit after tax, representing
total comprehensive income for the year
|
|
9,705
|
|
|
|
Proportion of the Group's
ownership interest in the associate
|
|
27.2%
|
|
|
|
Share of profit of the
associate
|
|
2,640
|
|
|
|
Dividends received from the
associate during the year
|
|
(3,842)
|
26. INTERESTS IN OPERATIONS
Details of the operations, of
which all are in production except for 46/07 and 51 which are in
the exploration stage while the Lemang PSC is in the development
stage, are as follows:
|
|
|
Place of
|
Group effective working
interest % as at 31 December
|
Contract Area
|
Date of expiry
|
Held by
|
operations
|
2023
|
2022
|
|
|
|
|
|
|
Montara
oilfield
|
Indefinite
|
Jadestone Energy (Eagle) Pty
Ltd
|
Australia
|
100
|
100
|
Stag Oilfield
|
25 August 2039
|
Jadestone Energy (Australia) Pty
Ltd
|
Australia
|
100
|
100
|
PM329
|
8 December
2031
|
Jadestone Energy (Malaysia) Pte
Ltd
|
Malaysia
|
70
|
70
|
PM323
|
14 June 2028
|
Jadestone Energy (Malaysia) Pte
Ltd
|
Malaysia
|
60
|
60
|
PM318
|
24 May 2034
|
Jadestone Energy (PM)
Inc.
|
Malaysia
|
100
|
50
|
AAKBNLP
|
24 May 2024
|
Jadestone Energy (PM)
Inc.
|
Malaysia
|
100
|
50
|
WA-3-L
|
Indefinite
|
Jadestone Energy (CWLH) Pty
Ltd
|
Australia
|
17
|
17
|
WA-9-L
|
15 July 2033
|
Jadestone Energy (CWLH) Pty
Ltd
|
Australia
|
17
|
17
|
WA-11-L
|
4 September
2035
|
Jadestone Energy (CWLH) Pty
Ltd
|
Australia
|
17
|
17
|
WA-16-L
|
11 September
2039
|
Jadestone Energy (CWLH) Pty
Ltd
|
Australia
|
17
|
17
|
46/07
|
29 June 2035
|
Mitra Energy (Vietnam Nam Du)
Pte
Ltd
|
Vietnam
|
100
|
100
|
51
|
10 June 2040
|
Mitra Energy (Vietnam Tho Chu)
Pte
Ltd
|
Vietnam
|
100
|
100
|
Lemang
|
17 January
2037
|
Jadestone Energy (Lemang) Pte
Ltd
|
Indonesia
|
100
|
100
|
Sinphuhorm concessions
(E5N)
|
15 March 2031
|
Jadestone Energy (Thailand) Pte
Ltd
|
Thailand
|
10
|
-
|
Sinphuhorm concessions
(EU1)
|
2 June 2029
|
Jadestone Energy (Thailand) Pte
Ltd
|
Thailand
|
10
|
-
|
Dong Mun (L27/43)
|
24 September
20171
|
Jadestone Energy (Thailand) Pte
Ltd
|
Singapore
|
27
|
-
|
1 The application for the extension to the license is currently
ongoing and managed by the associate, APICO LLC.
27. DEFERRED TAX
The following are the deferred tax
liabilities and assets recognised by the Group and movements
thereon.
|
Australian
PRRT
USD'000
|
|
Malaysian
PITA
USD'000
|
|
Tax
depreciation
USD'000
|
|
Derivative financial
instruments
USD'000
|
|
Total
USD'000
|
|
|
|
|
|
|
|
|
|
|
As at 1 January 2022
(Restated)*
|
14,546
|
|
7,342
|
|
(75,584)
|
|
-
|
|
(53,696)
|
Charged to profit or
loss (Note 16)
|
(7,032)
|
|
(5,737)
|
|
(14,087)
|
|
-
|
|
(26,856)
|
Acquisition of CWLH
Assets (Note 19)
|
(6,201)
|
|
-
|
|
19,390
|
|
-
|
|
13,189
|
|
|
|
|
|
|
|
|
|
|
As at 31 December
2022 (Restated)*
|
1,313
|
|
1,605
|
|
(70,281)
|
|
-
|
|
(67,363)
|
Charged to profit or
loss (Note 16)
|
4,269
|
|
(2,155)
|
|
20,138
|
|
-
|
|
22,252
|
Credited to OCI
|
-
|
|
-
|
|
-
|
|
6,056
|
|
6,056
|
|
|
|
|
|
|
|
|
|
|
As at 31 December
2023
|
5,582
|
|
(550)
|
|
(50,143)
|
|
6,056
|
|
(39,055)
|
The following is the analysis of
the deferred tax balances (after offset) for financial reporting
purposes:
|
|
31 December
2023
USD'000
|
|
31 December
2022
Restated*
USD'000
|
|
1 January
2022
Restated*
USD'000
|
|
|
|
|
|
|
|
Deferred tax
liabilities
|
|
(65,829)
|
|
(76,481)
|
|
(77,562)
|
Deferred tax assets
|
|
26,774
|
|
9,118
|
|
23,866
|
|
|
|
|
|
|
|
|
|
(39,055)
|
|
(67,363)
|
|
(53,696)
|
The Group's deferred tax assets
predominately arising from its Australian operations and PenMal
Assets. Deferred tax assets are recognised as the Directors
believe there will be sufficient taxable profits from its
Australian and Malaysian producing assets to offset against the
available future deductions based on the estimated future cash
flows prepared.
The Group has unutilised PRRT
credits of approximately US$3.8 billion (2022: US$3.5 billion;
2021: US$3.4 billion) and US$493.4 million (2022: US$535.5 million;
2021: nil) available for offset against future PRRT taxable profits
in respect of the Montara field and the CWLH Assets,
respectively. The PRRT credits remain effective throughout
the production licence of Montara and the CWLH Assets. No
deferred tax asset has been recognised in respect of these PRRT
credits, due to the Directors' projections
that the historic accumulated PRRT net losses are larger than
cumulative future expected PRRT taxable profits. As PRRT
credits are utilised based on a last-in-first-out basis, the
unutilised PRRT credits of approximately US$3.8 billion (2022:
US$3.5 billion; 2021: US$3.4 billion) and US$493.4 million (2022:
US$535.5 million; 2021: nil) with respect to Montara and the CWLH
Assets are not expected to be utilised and are therefore not
recognised as a deferred tax asset.
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
28. INVENTORIES
|
|
2023
USD'000
|
|
2022
Reclassified*
USD'000
|
|
|
|
|
|
Materials and spares
|
|
23,242
|
|
18,969
|
Less: allowance for slow moving
(Note 10)
|
|
(7,010)
|
|
(6,334)
|
|
|
|
|
|
|
|
16,232
|
|
12,635
|
|
|
|
|
|
Crude oil inventories
|
|
17,422
|
|
7,009
|
|
|
|
|
|
|
|
33,654
|
|
19,644
|
The cost of inventories recognised
as an expense during the year for lifted volumes, is calculated by
including production costs excluding workovers, Malaysian
supplementary payments and tariffs and transportation costs, plus
depletion expense of oil & gas properties, and plus
depreciation of right-of-use assets deployed for operational
use. In 2023, this cost totalled US$274.4 million (2022:
US$260.4 million).
29. TRADE AND OTHER RECEIVABLES
|
|
2023
USD'000
|
|
2022
Reclassified*
USD'000
|
|
|
|
|
|
Current assets
|
|
|
|
|
Trade receivables
|
|
12,533
|
|
6,332
|
Prepayments
|
|
5,947
|
|
3,119
|
Other receivables and
deposits
|
|
88,005
|
|
4,126
|
Amount due from joint arrangement
partners (net)
|
|
12,911
|
|
4,268
|
Underlift crude oil
inventories
|
|
3,539
|
|
107
|
GST/VAT receivables
|
|
1,444
|
|
1,683
|
|
|
|
|
|
|
|
124,379
|
|
19,635
|
|
|
|
|
|
Non-current assets
|
|
|
|
|
Other
receivables
|
|
127,730
|
|
83,192
|
VAT receivables
|
|
14,130
|
|
7,398
|
|
|
|
|
|
|
|
141,860
|
|
90,590
|
|
|
|
|
|
|
|
266,239
|
|
110,225
|
Trade receivables arise from
revenues generated from the Group's respective sole customer in
Australia and Malaysia. The average credit period is 30 days
(2022: 30 days). All outstanding receivables as at 31
December 2023 and 2022 have been recovered in full in 2024 and
2023, respectively.
*Certain 2022 comparative
information has been reclassified between line items. Please refer
to Note 50.
The current other receivables as
at 31 December 2023 mainly represent the accumulated cess payment
paid to the Malaysian regulator for the PenMal PNLP Assets and an
amount due from a joint arrangement partner for its share of future
wells preservation activities and decommissioning costs when it
exited two PSC licences during 2023. The receivable was
received in January 2024.
Amount due from joint arrangement
partners represents cash calls receivable from the Malaysian joint
arrangement partner, net of joint arrangement expenditures.
The amount is unsecured, with a credit period of 15 days. A
notice of default will be served to the joint arrangement partner
if the credit period is exceeded, which will become effective seven
days after service of such notice if the outstanding amount remains
unpaid. Interest of 3% per annum will be imposed on the
outstanding amount, starting from the effective date of
default. The outstanding receivable was received in January
2024.
The underlift crude oil
inventories represent entitlement imbalances at year end of 54,079
bbls at the PenMal operated assets. The underlift position is
measured at cost of US$18.75/bbl. The 2023 underlift position
will unwind in 2024 based on the subsequent net productions
entitled to the Group. The Group was in overlift position at
2022 year end which unwound in 2023 based on actual production
entitlement during the year. The underlift crude oil
inventories also consist of 32,411 bbls at the PNLP Assets being
the underlift position inherited by the Group following the
assumption of operatorship of the PNLP Assets from the previous
operator. The underlift position is measured at fair value of
US$77.91/bbl in view of there was no production at the PNLP Assets
during the year.
Non-current other receivables
represent the accumulated cess payment paid to the Malaysian and
Indonesian regulators for the operated licences and an abandonment
trust fund set up following the acquisition of the CWLH
Assets. The Malaysian PSCs and Lemang PSC require upstream
operators to contribute periodic cess payments to a cess
abandonment fund throughout the production life of the upstream oil
and gas assets, while the abandonment trust fund was set up as part
of the acquisition of the CWLH Assets. The payments made were
to ensure there are sufficient funds available for decommissioning
expenditures activities at the end of the fields' life. The
cess payment amount is assessed based on the estimated future
decommissioning expenditures.
The increase of non-current other
receivables during the period represents additional payments of
US$41.0 million into the CWLH abandonment trust fund.
Additionally, the total accumulated cess payment paid to the
Malaysian regulator and the ARO provision for the PNLP Assets are
now presented on a gross basis following the reallocation of the
CESS funds when the licenses and operatorship were transferred to
the Group in April 2023, in line with the Group's accounting
policies. In 2022, the total accumulated cess payment paid
and the ARO provision was presented on a net basis to reflect the
PSCs were non-operated, in line with the Group's accounting
policies. See Note 37 for further details.
The non-current VAT receivables
are associated with the Lemang PSC. It is classified as a
non-current asset as the recovery of the VAT receivables is
dependent on the share of revenue entitlement by the Indonesian
government after the commencement of gas production, which is
expected to occur in the first half of 2024.
There are no trade receivables
older than 30 days. The credit risk associated with the trade
receivables is disclosed in Note 44.
30. CASH AND BANK BALANCES
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Cash and bank balances,
representing cash and cash equivalents in the
consolidated
statement of cash flows,
presented as:
|
|
|
|
|
Non-current
|
|
1,008
|
|
676
|
Current
|
|
152,396
|
|
122,653
|
|
|
|
|
|
|
|
153,404
|
|
123,329
|
The non-current cash and cash
equivalents represents the restricted cash balance of US$0.7
million (2022: US$0.4 million) and US$0.3 million (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. These bank guarantees are expected to be in
place for a period of more than twelve months.
Current cash and cash equivalents
include a bank guarantee of US$0.5 million placed by the Group
during the year with respect to the construction of the Lemang PSC
gas pipeline facilities. This bank guarantee expired in
February 2024.
As part of the RBL facility, the
Group must retain an aggregate amount of principal, interest, fees
and costs payable for the next two quarters in the debt service
reserve account ("DSRA"). An amount of US$8.2 million was
deposited into the DSRA during 2023 and it is classified as a
current asset.
31. SHARE CAPITAL AND SHARE PREMIUM
ACCOUNT
|
|
Share
capital
|
|
Share premium
account
|
|
|
No. of
shares
|
|
USD'000
|
|
USD'000
|
|
|
|
|
|
|
|
Issued and fully paid
|
|
|
|
|
|
|
As at 1 January 2022, at £0.001
each
|
|
465,081,238
|
|
358
|
|
201
|
Issued during the year
|
|
1,446,108
|
|
2
|
|
782
|
Share repurchased
|
|
(18,173,683)
|
|
(21)
|
|
-
|
|
|
|
|
|
|
|
As at 31 December 2022
|
|
448,353,663
|
|
339
|
|
983
|
Issued during the year
|
|
94,463,933
|
|
120
|
|
50,844
|
Share repurchased
|
|
(2,051,022)
|
|
(3)
|
|
-
|
|
|
|
|
|
|
|
As at 31 December 2023
|
|
540,766,574
|
|
456
|
|
51,827
|
On 2 August 2022, the Company
announced the launch of a share buyback programme (the "Programme")
in accordance with the authority granted by the shareholders at the
Company's annual general meeting on 30 June 2022. The maximum
amount of the Programme was US$25.0 million, and the Programme will
not exceed 46,574,528 ordinary shares.
On 19 January 2023, the
Company suspended its share buyback programme. For the year ended 31
December 2023, the Company had acquired 2.3 million shares at a
weighted average cost of GB£0.75 per
share, resulting in total expenditure of US$2.1 million. The
total nominal value of the shares repurchased was US$2,485.
All shares repurchased were cancelled. Since the launch of
the share buyback programme, a total of 20.4 million shares had
been acquired for a total accumulated expenditure of US$18.1
million, with total nominal value of the shares repurchased was
US$23,778.
As at 31 December 2022, the
Company did not have a liability in respect to the remaining
unutilised amount of US$8.9 million under the Programme as the
Company had full discretion over the number of shares to be
repurchased. The Programme expired on 30 June 2023 in
conjunction with the Company's 2023 annual general meeting ("AGM")
and was not renewed at the 2023 AGM.
On 6 June 2023, the Company
completed an equity fundraising, creating an additional 94,081,826
ordinary shares at GB£0.45 per share, which comprised of a placing
and subscription of 92,312,691 new ordinary shares to existing and
new institutional shareholders and a placing and subscription of
1,769,135 new ordinary shares to the Directors of the
Company. Total gross proceeds were US$53.0 million, with net
proceeds of US$51.0 million. The Group incurred total costs
of US$2.0 million associated with the equity fundraising and these
costs were accounted as a deduction to the equity.
On 9 June 2023, the Company
launched an open offer of up to 14,887,039 new ordinary shares, at
GB£0.45 per share, to raise additional proceeds of up to EUR8.0
million1 (up to US$8.6 million). The open offer
closed on 28 June 2023, raising a total gross and net proceeds of
US$42,009 by issuing 73,557 new shares.
During the year, employee share
options of 128,160 were exercised and issued at an average price of
GB£ 0.56 per share (2022: 1,446,108; GB£0.42 per share).
Additionally, 79,327 shares were issued during the year to satisfy
the Company's obligations with regards to the performance shares
and 101,063 shares were issued to meet the obligations with regards
to the restricted shares.
The Company has one class of
ordinary share. Fully paid ordinary shares with par value of
GB£0.001 per share carry one vote per share without restriction,
and carry a right to dividends as and when declared by the
Company.
1 The open offer was quoted in Euro of 8.0 million to meet the
applicable regulation issued by the European Union regarding to the
quantum of open offer.
32. DIVIDENDS
The parent company has sufficient
distributable reserves to declare dividends. The
distributable reserves were created through the reduction of share
capital of the Company in May 2021. The dividends declared in
2022 were in compliance with the Act.
The Company did not declare any
dividend during the year.
On 20 September 2022, the
Directors declared a 2022 interim dividend of 0.65 US cents/share,
equivalent to a total distribution of US$3.0 million. The
dividend was paid on 11 October 2022.
On 6 June 2022, the Directors
recommended a final 2021 dividend of 1.34 US cents/share,
equivalent to a total distribution of US$6.2 million, or US$9.0
million in respect of total 2021 dividends. The dividend was
approved by shareholders on 30 June 2022 and paid on 5 July
2022.
33. 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.
34. SHARE-BASED PAYMENTS RESERVE
The total expense arising from
share-based payments of US$0.8 million (2022: US$1.0 million) was
recognised as 'administrative staff costs' (Note 7) in profit or
loss for the year ended 31 December 2023. The share-based
payment expense arise from share options, performance shares and
restricted shares awarded from 2020 to 2022. In view of the
performance of the Group in 2023, the Remuneration Committee
suspended performance share grants in 2023. In consultation
with an external advisor, the Remuneration Committee approved a
Deferred Cash Plan ("DCP") for the 2023 - 2026 Long-Term Incentive
("LTI") cycle, which was awarded in October 2023 (Note 41).
This was done to ensure that the LTI programme aligns the interests
of the senior leaders of the Group to the interests of
shareholders, and is effective in retaining and incentivising our
top talents.
On 15 May 2019, the Company
adopted, as approved by the shareholders, the amended and restated
stock option plan, the performance share plan, and the restricted
share plan (together, the "LTI Plans"), which establishes a rolling
number of shares issuable under the LTI Plans up to a maximum of
10% of the Company's issued and outstanding ordinary shares at any
given time. Options under the stock option plan will be
exercisable over periods of up to 10 years as determined by the
Board.
34.1 Share options
The Directors have applied the
Black-Scholes option-pricing model, with the following assumptions,
to estimate the fair value of the options at the date of
grant:
|
Options granted
on
|
|
9 March
2022
|
|
|
Risk-free rate
|
1.34% to
1.38%
|
Expected life
|
5.5 to
6.5 years
|
Expected
volatility1
|
63.0% to
66.7%
|
Share price
|
GB£
1.01
|
Exercise price
|
GB£
0.92
|
Expected dividends
|
1.96%
|
34.2 Performance shares
The performance measures for
performance shares incorporate both a relative and absolute total
shareholder return ("TSR") calculation on a 70:30 basis to compare
performance vs. peers (relative TSR) and to ensure alignment with
shareholders (absolute TSR).
Relative TSR: measured against the TSR of peer companies; the size of the
payout is based on Jadestone's ranking against the TSR outcomes of
peer companies.
Absolute TSR: share price target plus dividend to be set at the start of
the performance period and assessed annually; the threshold share
price plus dividend has to be equal to or greater than a 10%
increase in absolute terms to earn any pay out at all, and must be
25% or greater for target pay out.
A Monte Carlo simulation model was
used by an external specialist, with the following assumptions to
estimate the fair value of the performance shares at the date of
grant:
|
Performance shares granted
on
|
|
9 March
2022
|
|
|
Risk-free rate
|
1.39%
|
Expected volatility
|
53.1%
|
Share price
|
GB£
1.01
|
Exercise price
|
N/A
|
Expected dividends
|
1.71%
|
Post-vesting withdrawal
date
|
N/A
|
Early exercise
assumption
|
N/A
|
1 Expected volatility was determined by calculating the average
historical volatility of the daily share price returns over a
period commensurate with the expected life of the awards for a
group of ten peer companies.
2 Expected volatility was determined by calculating Jadestone's
average historical volatility of each trading day's log growth of
TSR over a period between the grant date and the end of the
performance period.
34.3 Restricted shares
Restricted shares are granted to
certain senior management personnel as an alternative to cash under
exceptional circumstances and to provide greater alignment with
shareholder objectives. These are shares that vest three
years after grant, assuming the employee has not left the
Group. They are not eligible for dividends prior to
vesting.
The following assumptions were
used to estimate the fair value of the restricted shares at the
date of grant, discounting back from the date they will vest and
excluding the value of dividends during the intervening
period:
|
Restricted shares granted
on
|
|
|
22 August
2022
|
9 March
2022
|
|
|
|
Risk-free rate
|
1.73%
|
1.39%
|
Share price
|
GB£
0.90
|
GB£
1.01
|
Expected dividends
|
1.73%
|
1.71%
|
|
|
|
|
The following table summarises the
options/shares under the LTI plans outstanding and exercisable as
at 31 December 2023:
|
Performance
shares
|
Restricted
shares
|
Shares
Options
|
|
Number of
options
|
Weighted
average
exercise
price GB£
|
Weighted
average
remaining
contract
life
|
Number
of options
exercisable
|
|
|
|
|
|
|
|
As at 1 January 2022
|
1,486,893
|
151,633
|
21,166,802
|
0.45
|
7.15
|
11,409,854
|
New options/share
awards issued
|
1,406,956
|
293,655
|
1,030,366
|
0.92
|
9.19
|
-
|
Vested during the
year
|
-
|
-
|
-
|
0.50
|
6.27
|
2,010,007
|
Accelerated vesting
during the year
|
-
|
-
|
-
|
0.46
|
6.45
|
1,354,702
|
Exercised during the
year
|
-
|
-
|
(1,446,108)
|
0.42
|
-
|
(1,446,108)
|
Cancelled during the
year
|
(147,906)
|
-
|
(1,012,124)
|
0.50
|
-
|
(1,012,124)
|
|
|
|
|
|
|
|
As at 31 December
2022
|
2,745,943
|
445,288
|
19,738,936
|
0.45
|
7.15
|
12,316,331
|
Vested during the
year
|
(79,327)
|
(101,063)
|
-
|
0.44
|
6.32
|
4,665,000
|
Exercised during the
year
|
-
|
-
|
(128,160)
|
0.56
|
-
|
(128,160)
|
Expired
unexercised
during the year
|
(449,513)
|
-
|
-
|
-
|
-
|
-
|
Cancelled during the
year
|
-
|
-
|
(344,655)
|
0.60
|
-
|
(344,655)
|
|
|
|
|
|
|
|
As at 31 December
2023
|
2,217,103
|
344,225
|
19,266,121
|
0.48
|
5.37
|
16,508,516
|
The weighted average share price
on the exercise date is GB£0.83 (2022:
GB£0.86).
|
Number of
options
|
Range of
exercise
price
GB£
|
Weighted
average
exercise
price GB£
|
Weighted
average
remaining
contract
life
|
|
|
|
|
|
Share options exercisable as at 31 December
2022
|
12,316,331
|
0.26 -
0.99
|
0.41
|
5.46
|
|
|
|
|
|
Share options exercisable as at 31 December
2023
|
16,508,516
|
0.26 -
0.99
|
0.41
|
4.92
|
35. CAPITAL REDEMPTION RESERVE
The capital redemption reserve
arose from the Programme launched by the Company in August
2022. It represents the par value of the shares purchased and
cancelled by the Company under the Programme (Note 31).
36. HEDGING RESERVE
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
At beginning of the year
|
|
-
|
|
-
|
Loss arising on changes in fair
value of hedging instruments during the year
|
|
30,509
|
|
-
|
Income tax related to loss
recognised in other comprehensive income
|
|
(9,153)
|
|
-
|
Net loss reclassified to profit or
loss (Note 4)
|
|
(10,322)
|
|
-
|
Income tax related to amounts
reclassified to profit or loss
|
|
3,097
|
|
-
|
|
|
|
|
|
At end of the year
|
|
14,131
|
|
-
|
The hedging reserve represents the
cumulative amount of gains and losses on hedging instruments deemed
effective in cash flow hedges. The cumulative deferred gain
or loss on the hedging instrument is recognised in profit or loss
only when the hedged transaction impacts the profit or loss.
See Note 42 for further details on the hedging
arrangements.
37. PROVISIONS
|
|
Asset restoration
obligations
(a)
USD'000
|
|
Contingent
payments
(b)
USD'000
|
|
Employees
benefits
(c)
USD'000
|
|
Others
USD'000
|
|
Total
USD'000
|
|
|
|
|
|
|
|
|
|
|
|
As at 1 January 2022
|
|
404,401
|
|
6,179
|
|
844
|
|
202
|
|
411,626
|
Charged/(Credited) to profit or
loss
|
|
-
|
|
-
|
|
122
|
|
(202)
|
|
(80)
|
Acquisition of CWLH Assets (Note
19)
|
|
64,633
|
|
1,940
|
|
-
|
|
-
|
|
66,573
|
Acquisition of 10% interest in
Lemang PSC (Note 20)
|
|
337
|
|
-
|
|
-
|
|
-
|
|
337
|
Accretion expense (Note
14)
|
|
8,333
|
|
-
|
|
-
|
|
-
|
|
8,333
|
Changes in discount rate
assumptions (Note 22)
|
|
18,687
|
|
-
|
|
-
|
|
-
|
|
18,687
|
Payment/Utilised
|
|
-
|
|
-
|
|
(81)
|
|
-
|
|
(81)
|
Change in provision (Note
10)
|
|
-
|
|
7,333
|
|
-
|
|
-
|
|
7,333
|
Fair value adjustment - Lemang PSC (Note 14)
|
|
-
|
|
349
|
|
-
|
|
-
|
|
349
|
Fair value adjustment - PenMal Assets (Note 14)
|
|
-
|
|
1,571
|
|
-
|
|
-
|
|
1,571
|
Reclassification
|
|
-
|
|
(3,000)
|
|
-
|
|
-
|
|
(3,000)
|
|
|
|
|
|
|
|
|
|
|
|
As at 31 December 2022 (Restated)*
|
|
496,391
|
|
14,372
|
|
885
|
|
-
|
|
511,648
|
Charged/(Credited) to profit or
loss
|
|
-
|
|
(7,653)
|
|
149
|
|
1,112
|
|
(6,392)
|
Accretion expense (Note
14)
|
|
20,201
|
|
-
|
|
-
|
|
-
|
|
20,201
|
Changes in discount rate
assumptions (Notes 12 and 22)
|
|
19,420
|
|
-
|
|
-
|
|
-
|
|
19,420
|
Payment/Utilised
|
|
(8,589)
|
|
-
|
|
-
|
|
-
|
|
(8,589)
|
Fair value adjustment - Lemang PSC (Note 14)
|
|
-
|
|
868
|
|
-
|
|
-
|
|
868
|
Fair value adjustment - CWLH Assets (Note 14)
|
|
-
|
|
60
|
|
-
|
|
-
|
|
60
|
Acquisition of 50% interest in
PNLP Assets
|
|
48,430
|
|
-
|
|
-
|
|
-
|
|
48,430
|
Gross Up (Note 29)
|
|
28,176
|
|
-
|
|
-
|
|
-
|
|
28,176
|
Reclassification
|
|
(127)
|
|
(2,000)
|
|
-
|
|
-
|
|
(2,127)
|
|
|
|
|
|
|
|
|
|
|
|
As at 31 December 2023
|
|
603,902
|
|
5,647
|
|
1,034
|
|
1,112
|
|
611,695
|
|
|
|
|
|
|
|
|
|
|
|
As at 31 December 2022
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
-
|
|
-
|
|
703
|
|
-
|
|
703
|
Non-current
|
|
496,391
|
|
14,372
|
|
182
|
|
-
|
|
510,945
|
|
|
|
|
|
|
|
|
|
|
|
|
|
496,391
|
|
14,372
|
|
885
|
|
-
|
|
511,648
|
|
|
|
|
|
|
|
|
|
|
|
As at 31 December 2023
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
102,811
|
|
5,000
|
|
714
|
|
-
|
|
108,525
|
Non-current
|
|
501,091
|
|
647
|
|
320
|
|
1,112
|
|
503,170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
603,902
|
|
5,647
|
|
1,034
|
|
1,112
|
|
611,695
|
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
(a)
The Group's ARO comprise the future estimated
costs to decommission each of the Montara, Stag, Lemang PSC, PenMal
Assets and CWLH Assets.
The carrying value of the
provision represents the discounted present value of the estimated
future costs. Current estimated costs of the ARO for each of
the Montara, Stag, Lemang PSC, PenMal Assets and CWLH Assets have
been escalated to the estimated date at which the expenditure would
be incurred, at an assumed blended inflation rate. The
estimates for each asset are a blend of assumed US and respective
local inflation rates to reflect the underlying mix of US dollar
and respective local dollar denominated expenditures. The
present value of the future estimated ARO for each of the Montara,
Stag, Lemang PSC, PenMal Assets and CWLH Assets has then been
calculated based on a blended risk-free rate. The base
estimate ARO for Montara, Stag, Lemang PSC, PenMal Assets and CWLH
Assets remains largely unchanged from 2022. The blended
inflation rates and risk-free rates used, plus the estimated
decommissioning year of each asset are as follows:
No.
|
Asset
|
Blended inflation
rate
|
Blended risk-free
rate
|
Estimated decommissioning
year
|
2023
|
2022
|
2023
|
2022
|
|
|
|
|
|
|
|
1.
|
Montara
|
2.55%
|
3.01%
|
3.99%
|
3.97%
|
2031
|
2.
|
Stag
|
2.30%
|
2.62%
|
4.08%
|
4.01%
|
2036
|
3.
|
Lemang PSC
|
2.24%
|
2.93%
|
6.09%
|
6.43%
|
2036
|
4.
|
PenMal Assets
|
2.09%
|
2.46% -
2.48%
|
3.52% -
3.80%
|
3.48% -
4.02%
|
2024
onwards
|
5.
|
CWLH Assets
|
2.58%
|
3.05%
|
4.03%
|
3.94%
|
2035
|
Following the enactment of the
Offshore Petroleum and Greenhouse Gas Storage Amendment (Titles
Administration and Other Measures) Act 2021 which, amongst other
things, enhanced the decommissioning framework applying to offshore
assets in Australia, on 29 March 2023 Jadestone Energy (Australia)
Pty Ltd, Jadestone Energy (Eagle) Pty Ltd and Jadestone Energy
(CWLH) Pty Ltd, each wholly owned subsidiaries of the Company,
entered into a deed poll with the Australian Government with regard
to the requirements of maintaining sufficient financial capacity to
ensure that each of Montara's, Stag's and CWLH's asset restoration
obligations can be met when due. The deed states that the
Group is required to provide financial security in favour of the
Australian Government when the aggregate remaining net after-tax
cash flow of the Group is below 1.25 times of the Group's estimated
decommissioning liabilities net of any residual value, tax
benefits, and other financial assurance committed by the Group for
such purposes. The Group does not expect to provide financial
security under the deed poll this year based on the financial
capacity assessment.
The Malaysian and Indonesian
regulators require upstream oil and gas companies to contribute to
an abandonment cess fund, including making monthly cess payments,
throughout the production life of the oil or gas field. The
cess payment amount is assessed based on the estimated future
decommissioning expenditures. The cess payment paid for
non-operated licences reduces the ARO liability. The
Malaysian abandonment cess fund only covers the decommissioning
costs related to the oil and gas facilities, excluding wells.
The Indonesian cess fund covers the decommissioning costs related
to all facilities. The Group has recognised ARO provisions
for the estimated decommissioning costs of the wells in the
PSCs.
An abandonment trust fund was set
as part of the acquisition of the CWLH Assets to ensure there are
sufficient funds available for decommissioning activities at the
end of field life. The cash contribution paid into the trust
fund is classified as non-current receivable as the amount is
reclaimable by the Group in the future following the commencement
of decommissioning activities.
(b)
The fair value of the contingent payments payable
to Mandala Energy Lemang Pte Ltd for the Lemang PSC acquisition are
valued at US5.6 million as at 31 December 2023 (2022: US$12.4
million) for the trigger events as disclosed below. The
decrease in provision represents the derecognition of contingent
payments associated with the Saudi CP and Dated Brent prices due to
the trigger events are not expected to occur based on the
specialist's consensus on Dated Brent prices and the historical
correlation between Dated Brent prices and Saudi CP.
No.
|
Trigger
event
|
Consideration
|
Directors'
rationale
|
|
|
|
|
1.
|
First gas date
|
US$5.0
million
|
This contingent payment is
virtually certain as it will be payable when gas production in the
Lemang PSC is commenced.
|
2.
|
The accumulated VAT receivables
reimbursements which are attributable to the unbilled VAT in the
Lemang Block as at the Closing Date, exceeding an aggregate amount
of US$6.7 million on a gross basis
|
US$0.7
million
|
The Directors estimated that the
accumulated receipts of VAT reimbursements received will exceed
US$6.7 million on a gross basis.
|
3.
|
First gas date on or before 31
March 2023
|
US$3.0
million
|
Not payable as the trigger event
has expired. First gas is scheduled in first half of
2024.
|
4.
|
Total actual Akatara Gas Project
"close out" costs set out in the AFE(s) approved pursuant to a
joint audit by SKK MIGAS and BPKP is less than, or within 2% of the
"close out" development costs set out in the approved revised plan
of development for the Akatara Gas Project
|
US$3.0
million
|
Based on the status of the Akatara
Gas Project as at 2023 year end, the actual "close out" costs set
out in the AFE(s) has exceeded the "close out" development costs
set out in the approved revised plan by more than 2%. As
such, the consideration trigger will not be met.
|
5.
|
The average Saudi CP in the first
year of operation is higher than US$620/MT
|
US$3.0
million
|
The average Saudi CP is not
expected to be above US$620/MT in 2024, with the first gas is
anticipated to be in H1 2024. The contingent payment will be
due for payment within 15 business days of the occurrence of the
trigger event if it falls due.
|
6.
|
The average Saudi CP in the second
year of operation is higher than US$620/MT
|
US$2.0
million
|
The average Saudi CP is not
expected to be above US$620/MT in 2025, the second year of
production. The contingent payment will be due for payment
within 15 business days of the occurrence of the trigger event if
it falls due.
|
7.
|
The average Dated Brent price in
the first year of operation is higher than US$80/bbl
|
US$2.5
million
|
The average Dated Brent price is
not expected to be above US$80/bbl in 2024, with the first gas is
anticipated to be in H1 2024. The contingent payment will be
due for payment within 15 business days of the occurrence of the
trigger event if it falls due.
|
No.
|
Trigger
event
|
Consideration
|
Directors'
rationale
|
|
|
|
|
8.
|
The average Dated Brent price in
the second year of operation is higher than US$80/bbl
|
US$1.5
million
|
The average Dated Brent price is
not expected to be above US$80/bbl in 2025, the second year of
production. The contingent payment will be due for payment
within 15 business days of the occurrence of the trigger event if
it falls due.
|
9.
|
A plan of development for the
development of a new discovery made, as a result of the remaining
exploration well commitment under the PSC, is approved by the
relevant government entity.
|
US$3.0
million
|
There are no prospects or leads
presently selected for the exploration well commitment. As at
year end, it is not probable that this contingent consideration
trigger will be met.
|
10.
|
The plan of development described
in item 9 above is approved by the relevant government entity and
is based on reserves of no less than 8.4mm barrels (on a gross
basis).
|
US$8.0
million
|
There are no prospects or leads
presently selected for the exploration well commitment. As at
year end, it is not probable that this contingent consideration
trigger will be met.
|
(c)
Included in the provision for employee benefits
is provision for long service leave which is payable to employees
on a pro-rata basis after 7 years of employment and is due in full
after 10 years of employment.
38. BORROWINGS
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Non-current secured borrowings
|
|
|
|
|
Reserve based lending
facility
|
|
147,313
|
|
-
|
|
|
|
|
|
Current secured borrowings
|
|
|
|
|
Reserve based lending
facility
|
|
7,260
|
|
-
|
|
|
|
|
|
|
|
154,573
|
|
-
|
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 in support of the acquisition of the Sinphuhorm
Assets. In February 2023, US$28.5 million was utilised to
fund the acquisition of the Sinphuhorm Assets. A 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
14.
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 tail1 (which is expected
later). As at 31 December 2023, 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 31 December 2023 was US$200.0 million. 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, and to deliver the required information to the RBL Banks
on a timely basis.
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.
As at 31 December 2023, the Group
has a net drawdown sum of US$157.0 million. The loan incurred
costs of US$7.1 million and the fair value of the loans at drawdown
had an amortised carrying value of US$149.9 million. For the
year ended 31 December 2023, the Group had incurred interest
expense of US$8.1 million and US$0.3 million of commitment fees,
which were recorded as finance costs in Note 14.
On 6 June 2023, the Company
entered into a committed standby working capital facility with
Tyrus Capital Events S.a.r.l.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 (Note 31). The facility will
mature on 31 December 2024. The facility bears interest of
15% on drawn amounts and 5% on undrawn amounts and can be repaid or
cancelled without penalties. The standby working capital
facility was not utilised during 2023 and remained undrawn as at 31
December 2023. See Note 49 for further details. For the
year ended 31 December 2023, the Group had incurred interest
expense of US$3.6 million, which was recorded as finance costs in
Note 14.
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.
39. LEASE LIABILITIES
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Presented as:
|
|
|
|
|
Non-current
|
|
18,746
|
|
2,880
|
Current
|
|
14,118
|
|
6,227
|
|
|
|
|
|
|
|
32,864
|
|
9,107
|
|
|
|
|
|
Maturity analysis of lease
liabilities based on undiscounted gross cash flows:
|
|
|
|
|
Year 1
|
|
17,357
|
|
6,649
|
Year 2
|
|
14,662
|
|
2,261
|
Year 3
|
|
3,674
|
|
426
|
Year 4
|
|
-
|
|
334
|
Year 5
|
|
-
|
|
-
|
Future interest charge
|
|
(2,829)
|
|
(563)
|
|
|
|
|
|
|
|
32,864
|
|
9,107
|
The Group does not face a
significant liquidity risk with regards to its lease
liabilities. Lease liabilities are monitored within the
Group's treasury function.
40. RECONCILIATION OF LIABILITIES ARISING FROM
FINANCING ACTIVITIES
The table below details changes in
the Group's liabilities arising from financing activities,
including both cash and non-cash changes. Liabilities arising
from financing activities are those for which cash flows were, or
future cash flows will be, classified in the Group's consolidated
statement of cash flows, as cash flows from financing
activities.
The cash flows represent the
repayment of borrowings and lease liabilities, in the consolidated
statement of cash flows.
|
Borrowings
USD'000
|
|
Lease
liabilities
USD'000
|
|
|
|
|
As at 1 January 2022
|
-
|
|
15,665
|
Financing cash flows
|
-
|
|
(13,914)
|
New lease liabilities
|
-
|
|
7,356
|
Interest paid
|
-
|
|
(769)
|
Non-cash changes -
interest
|
-
|
|
769
|
|
|
|
|
As at 31 December 2022
|
-
|
|
9,107
|
Financing cash flows
|
(75,000)
|
|
(14,400)
|
New borrowings
|
232,000
|
|
|
New lease liabilities
|
-
|
|
38,157
|
Borrowings costs paid
|
(7,595)
|
|
-
|
Interest paid
|
(5,007)
|
|
(2,771)
|
RBL commitment fees
paid
|
(658)
|
|
-
|
Interest expense
|
2,571
|
|
-
|
RBL commitment fees
|
349
|
|
-
|
Non-cash changes -
interest
|
5,518
|
|
2,771
|
Capitalisation of borrowing
costs
|
2,395
|
|
-
|
|
|
|
|
As at 31 December 2023
|
154,573
|
|
32,864
|
41. TRADE AND OTHER PAYABLES
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
Current
|
|
|
|
|
Trade payables
|
|
36,056
|
|
13,606
|
Other payables
|
|
9,100
|
|
8,643
|
Accruals
|
|
56,534
|
|
36,757
|
Contingent payments
|
|
2,000
|
|
5,000
|
Malaysian supplementary payment
payables
|
|
2,152
|
|
855
|
Amount due to joint arrangement
partner
|
|
1,252
|
|
1,269
|
Overlift crude oil
inventories
|
|
6,004
|
|
6,957
|
GST/VAT payables
|
|
881
|
|
265
|
|
|
|
|
|
|
|
113,979
|
|
73,352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current
|
|
|
|
|
Other payable
|
|
16,917
|
|
-
|
Accrual
|
|
49
|
|
-
|
|
|
|
|
|
|
|
16,966
|
|
-
|
|
|
|
|
|
|
|
130,945
|
|
73,352
|
Trade payables, other payables and
accruals principally comprise amounts outstanding for trade and
non-trade related purchases and ongoing costs. The average
credit period taken for purchases is 30 days (2022: 30 days).
For most suppliers, no interest is charged on the payables in the
first 30 days from the date of invoice. Thereafter, interest
may be charged on outstanding balances at varying rates of
interest. The Group has financial risk management policies in
place to ensure that all payables are settled within the pre-agreed
credit terms.
The contingent payment in 2023
relates to the final contingent payment payable to BP which arose
from the acquisition of the CWLH Assets (Note 19) as the annual
average Brent crude price in 2023 exceeded US$60/bbl. The
payment was made in January 2024. The contingent payments in
2022 represented the final contingent payment of US$3.0 million
payable to SapuraOMV as the annual average Brent crude price in
2022 exceeded US$70/bbl (Note 37). The payment was made in
January 2023. In addition, the Group was obliged to pay to a
contingent payment of US$2.0 million to BP which arose from the
acquisition of the CWLH Assets (Note 19) as the annual average
Brent crude price in 2022 exceeded US$50/bbl. The payment was
made in January 2023.
The overlift crude oil inventories
represent entitlement imbalances at year end of 195,698 bbls at the
CWLH Assets (2022: CWLH Assets: 205,510 bbls; PenMal Assets: 31,076
bbls). The overlift liabilities are measured at cost of
US$30.68/bbl (2022: CWLH Assets: US$32.92/bbl; PenMal Assets:
US$19.07/bbl). The PenMal Assets are in an underlift position
as at 2023 year end (Note 29).
The non-current other payable
represents future activities which are operational in nature for
which cash advances are to be received from the Malaysian joint
arrangement partner for its share of future wells preservation activities and decommissioning
costs on the PNLP Assets when it
withdrew from the licences in 2023 (Note 29). The Group received the payment in
January 2024.
The non-current accrual represents
the DCP plan granted during the year as disclosed in Note 34.
The DCP has a duration of three years and will be settled by cash
on different payout rates at the end of three years subject to the
performance of the Group. The performance measures for DCP is
similar to the performance shares as disclosed in Note 34.2.
The DCP is measured at fair value as at 31 December
2023.
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
42. DERIVATIVE FINANCIAL INSTRUMENTS
|
|
2023
USD'000
|
|
2022
USD'000
|
|
|
|
|
|
Derivative financial liabilities
|
|
|
|
|
Designated as cash flow hedges
|
|
|
|
|
Commodity swap
|
|
24,612
|
|
-
|
|
|
|
|
|
Measured at fair value though profit or
loss
|
|
|
|
|
Foreign exchange forward
contracts
|
|
73
|
|
-
|
|
|
|
|
|
|
|
24,685
|
|
-
|
|
|
|
|
|
Analysed as:
|
|
|
|
|
Current
|
|
17,977
|
|
-
|
Non-current
|
|
6,708
|
|
-
|
|
|
|
|
|
|
|
24,685
|
|
-
|
The following is a summary of the
Group's outstanding derivative contracts:
Contract quantity
|
Type of contracts
|
Terms
|
Contract price
|
Hedge classification
|
Fair value asset at
31 December 2023
USD'000
|
Fair value asset at
31 December
2022
USD'000
|
|
|
|
|
|
|
|
Contracts designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
50% of
Group's
planned
2P
production
|
Commodity
swap:
swap
component
|
Oct
2023
-
Sep
2025
|
Weighted
average price of
US$70.57/bbl
|
Cash flow
|
(24,612)
|
-
|
|
|
|
|
|
|
|
Contracts that are not designated in hedge accounting
relationships
|
|
|
|
|
|
|
|
To hedge
MYR162.5
million by
selling MYR
for USD
|
Foreign
exchange
forward
contracts
|
Execution
date: 2
February
2024
|
USD/MYR: 4.60
|
FVTPL
|
(73)
|
-
|
The Group's October 2023 to
September 2025 commodity swap programme was designated as a cash
flow hedge. Critical terms of the commodity swap (i.e., the
notional amount, life and underlying oil price benchmark) and the
corresponding Group's hedged sales are highly similar. The
Group performed a qualitative assessment of the effectiveness of
the commodity swap contracts and concluded that the commodity swap
programme is highly effective as the value of the commodity swap
and the value of the corresponding hedged items will systematically
change in opposite directions in response to movements in the
underlying commodity prices.
In August 2023, the Group entered
into a foreign exchange forward contract with a bank based in
Malaysia to hedge MYR162.5 million (approximately US$35.4 million),
being the receivable sum at 2023 year end due from the joint
arrangement partner of PNLP Assets for its share of
future decommissioning costs when it exited two
PSC licences. The forward contract is to secure the receipts
in USD in view of volatility of MYR against USD towards the end of
2023. The forward contract matured on 2 February 2024
following the receipts of the sum from the joint arrangement
partner in January 2024.
The following tables detail the
commodity swap contracts outstanding at the end of the year, as
well as information regarding their related hedged items.
Commodity swap contract assets are included in the
"derivative financial instruments" line item in the consolidated
statement of financial position.
Hedging instruments - outstanding contracts
|
Oil
volumes
bbls
|
Notional
value
USD'000
|
Change in fair value used
for calculating hedge ineffectiveness
USD'000
|
Fair value
USD'000
|
|
|
|
|
|
2023
|
|
|
|
|
Cash flow hedges
|
|
|
|
|
Commodity swap
component
|
4,531,720
|
317,629
|
-
|
20,187
|
The following table details the
effectiveness of the hedging relationships and the amounts
reclassified from hedging reserve to profit or loss:
|
Current period hedging
(loss)/gain recognised in OCI
USD'000
|
Amount of hedge
ineffectiveness recognised in profit or loss
USD'000
|
Line item in profit or loss
in which hedge ineffectiveness is included
|
Amount reclassified to
profit or loss due to hedged item affecting profit or
loss
USD'000
|
Line item in profit or loss
in which reclassification adjustment is included
|
|
|
|
|
|
2023
|
|
|
|
|
Cash flow hedges
|
|
|
|
|
Forecast sales
|
(20,187)
|
-
|
Other
expenses
|
(10,322)
|
Revenue
|
43. WARRANTS LIABILITY
On 6 June 2023,
in consideration of the support provided to the
Company under the equity underwrite debt
facility and committed standby working capital facility, the
Company entered into a warrant instrument
with Tyrus Capital S.A.M. and funds
managed by it, for 30 million ordinary
shares at an exercise price of 50 pence sterling per share.
The warrants are exercisable within 36 months from the date of
issuance, with an expiry date of 5 June 2026.
The Directors have applied the
Black-Scholes option-pricing model, with the following assumptions,
to estimate the fair value of the warrants as at 31 December
2023:
Risk-free rate
|
3.77%
|
Expected life
|
2.5
years
|
Expected volatility
|
54.5%
|
Share price
|
GB£
0.37
|
Exercise price
|
GB£
0.50
|
Expected dividends
|
0%
|
1 Expected volatility was determined by calculating the
average historical volatility of the daily share price returns over
a period commensurate with the expected life of the awards for a
group of ten peer companies.
44. FINANCIAL INSTRUMENTS, FINANCIAL RISKS AND CAPITAL
MANAGEMENT
Financial assets and liabilities
Current assets and liabilities
The Directors consider that due to
the short-term nature of the Group's current assets and
liabilities, the carrying amounts equate to their fair
value.
Non-current assets and liabilities
The carrying amount of non-current
assets and liabilities approximates their fair values due to the
carrying amount representing the actual cash paid.
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
Financial assets
|
|
|
|
|
At amortised cost
|
|
|
|
|
Trade and other
receivables, excluding prepayments, GST/VAT receivables
and
underlift crude
oil inventories
|
|
241,179
|
|
97,918
|
Cash and bank
balances
|
|
153,404
|
|
123,329
|
|
|
|
|
|
|
|
394,583
|
|
221,247
|
|
|
|
|
|
Financial liabilities
|
|
|
|
|
At amortised cost
|
|
|
|
|
Trade and other payables,
excluding GST/VAT payables and overlift crude oil
inventories
|
|
122,060
|
|
61,130
|
Lease
liabilities
|
|
32,864
|
|
9,107
|
Borrowings
|
|
154,573
|
|
-
|
Contingent consideration for
Lemang PSC acquisition
|
|
5,647
|
|
12,432
|
Contingent consideration for CWLH
Assets acquisition
|
|
2,000
|
|
3,940
|
Contingent consideration for
PenMal Assets acquisition
|
|
-
|
|
3,000
|
Derivative financial instruments
designated as cash flow hedges
|
|
24,612
|
|
-
|
Derivative financial instrument
carried at FVTPL
|
|
73
|
|
-
|
|
|
|
|
|
|
|
341,829
|
|
89,609
|
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
Fair values are based on
the Directors'
best estimates, after consideration of current market
conditions. The estimates are subjective and involve
judgment, and as such may deviate from the amounts that the Group
realises in actual market transactions.
Commodity price risk
The Group's earnings are affected
by changes in oil prices. As part of the RBL, the Group
entered into commodity swap contracts to
hedge 50% of its forecasted production from October 2023 to
September 2025 (Note 42).
Commodity price sensitivity
The results of operations and cash
flows from oil and gas production can vary significantly with
fluctuations in the market prices of oil and/or natural gas.
These are affected by factors outside the Group's control,
including the market forces of supply and demand, regulatory and
political actions of governments, and attempts of international
cartels to control or influence prices, among a range of other
factors.
The table below summarises the
impact on (loss)/profit before tax, and on equity, from changes in
commodity prices on the fair value of derivative financial
instruments. The analysis is based on the assumption that the
crude oil price moves 10%, with all other variables held constant.
Reasonably possible movements in commodity prices were
determined based on a review of recent historical prices and
current economic forecasters' estimates.
Gain or loss
|
Effect on
the
result
before tax for
the
year ended
31 December
2023
USD'000
|
Effect on
other
comprehensive
income before
tax
for the year
ended
31 December
2023
USD'000
|
Effect on
the
result
before tax for
the
year ended
31 December
2022
USD'000
|
Effect on
other
comprehensive
income before
tax
for the year
ended
31 December
2022
USD'000
|
|
|
|
|
|
Increase by 10%
|
-
|
(33,861)
|
-
|
-
|
Decrease by 10%
|
-
|
33,861
|
-
|
-
|
Foreign currency risk
Foreign currency risk is the risk
that a variation in exchange rates between United States Dollars
("US Dollar") and foreign currencies will affect the fair value or
future cash flows of the Group's financial assets or liabilities
presented in the consolidated statement of financial position as at
year end.
Cash and bank balances are
generally held in the currency of likely future expenditures to
minimise the impact of currency fluctuations. It is the
Group's normal practice to hold the majority of funds in US
Dollars, in order to match the Group's revenue and
expenditures.
In addition to US Dollar, the
Group transacts in various currencies, including Australian Dollar,
Malaysian Ringgit, Vietnamese Dong, Indonesian Rupiah, Singapore
Dollar and British Pound Sterling.
The Group manages its foreign
currency risk by monitoring the fluctuations of material foreign
currencies against USD and potentially entering into foreign
currency forward contract to hedge against the currency
fluctuations if and when considered appropriate.
In August 2023, the Group entered
into a foreign exchange forward contract with a bank based in
Malaysia to hedge MYR162.5 million (approximately US$35.4 million),
being the receivable sum at 2023 year end due from the joint
arrangement partner of PNLP Assets for its share of
future decommissioning costs when it exited two
PSCs' licences. The forward contract was entered to secure
the receipts in USD in view of volatility of MYR against USD
towards the end of 2023. The forward contract was matured on
2 February 2024 following the receipts of the sum from the joint
arrangement partner in January 2024.
Foreign currency sensitivity
Material foreign denominated
balances were as follows:
|
|
2023
USD'000
|
|
2022
Restated*
USD'000
|
|
|
|
|
|
Cash and bank balances
|
|
|
|
|
Australian Dollars
|
|
4,777
|
|
11,086
|
Malaysian Ringgit
|
|
8,533
|
|
5,336
|
|
|
|
|
|
Trade and other receivables
|
|
|
|
|
Australian Dollars
|
|
250
|
|
1,966
|
Malaysian Ringgit
|
|
42,672
|
|
4,269
|
|
|
|
|
|
Trade and other payables
|
|
|
|
|
Australian Dollars
|
|
33,250
|
|
34,036
|
Malaysian Ringgit
|
|
59,113
|
|
12,422
|
A strengthening/weakening of the
Australian dollar and Malaysian Ringgit by 10%, against the
functional currency of the Group, is estimated to result in the net
carrying amount of Group's financial assets and financial
liabilities as at year end decreasing/increasing by approximately
US$3.5 million (2022: US$2.4 million), and which would be
charged/credited to the consolidated statement of profit or
loss.
*Certain 2022 comparative
information has been restated. Please refer to Note 50.
Interest rate risk
The Group's interest rate exposure
arises from its cash and bank balances, CWLH Assets abandonment
trust fund and borrowings. The Group's other financial
instruments are non-interest bearing or fixed rate, and are
therefore not subject to interest rate risk. The Group
continually monitors its cash position and places excess funds into
fixed term deposits as necessary.
As at 31 December 2023, the Group
held US$82.0 million (2022: US$41.0 million) in the CWLH Assets
abandonment trust fund operated by the joint venture operating
partner. The abandonment trust funds generates average annual
interest rate of 4.5% (2022: 3.6%).
As at 31 December 2023, the Group
held US$55.0 million (2022: nil) in fixed term deposits. The
fixed term deposits generate average annual interest rate of 4.5%
(2022: nil).
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 (which is expected later). The
borrowing base is secured over the Group's main producing assets
being Montara, Stag, CWLH, Sinphuhorm Assets, the PenMal PM323 and
PM329 PSCs and the Group's development asset being the Lemang
PSC. The borrowing base as at 31 December 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.
As at 31 December 2023, the Group
has a net drawdown sum of US$157.0 million. The loan incurred
costs of US$7.0 million.
Based on the carrying value of the CWLH Assets abandonment trust
fund, fixed term deposits and RBL as at 31 December 2023, if
interest rates had increased/decreased by 1% and all other
variables remained constant, the Group's net loss before tax would
be increased/decreased by US$0.1 million (2022: profit before tax
increased/decreased by US$0.4 million).
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.
Credit risk
Credit risk represents the
financial loss that the Group would suffer if a counterparty in a
transaction fails to meet its obligations in accordance with the
agreed terms.
The Group actively manages its
exposure to credit risk, granting credit limits consistent with the
financial strength of the Group's counterparties and respective
sole customer in Australia and Malaysia, requiring financial
assurances as deemed necessary, reducing the amount and duration of
credit exposures, and close monitoring of relevant
accounts.
The Group trades only with
recognised, creditworthy third parties.
The Group's current credit risk
grading framework comprises the following
categories:
Category
|
Description
|
Basis for recognising expected credit losses
("ECL")
|
Performing
|
The counterparty has a low risk of
default and does not have any past due amounts.
|
12-month ECL
|
Doubtful
|
Amount is > 30 days past due or
there has been a significant increase in credit risk since initial
recognition.
|
Lifetime ECL - not
credit-impaired
|
In default
|
Amount is > 90 days past due or
there is evidence indicating the asset is
credit-impaired.
|
Lifetime ECL -
credit-impaired
|
Write-off
|
There is evidence indicating that
the debtor is in severe financial difficulty and the Group has no
realistic prospect of recovery.
|
Amount is written off
|
The table below details the credit
quality of the Group's financial assets and other items, as well as
maximum exposure to credit risk by credit risk rating
grades:
|
|
External
credit
|
Internal
credit
|
12-month ("12m")
or
|
Gross carrying amount
(i)
Reclassified*
|
Loss
allowance
|
Net carrying
amount
Reclassified*
|
|
Note
|
rating
|
rating
|
lifetime
ECL
|
USD'000
|
USD'000
|
USD'000
|
|
|
|
|
|
|
|
|
2023
|
|
|
|
|
|
|
|
Cash and bank balances
|
30
|
n.a
|
Performing
|
12m
ECL
|
153,404
|
-**
|
153,404
|
Trade receivables
|
29
|
A2
|
(i)
|
Lifetime ECL
|
12,533
|
-**
|
12,533
|
Other receivables and
deposits
|
29
|
n.a
|
(i)
|
12m
ECL
|
88,005
|
-**
|
88,005
|
Amount due from joint
arrangement partners
(net)
|
29
|
n.a
|
(i)
|
12m
ECL
|
12,911
|
-**
|
12,911
|
Non-current other
receivables
|
29
|
n.a
|
(i)
|
12m
ECL
|
127,730
|
-**
|
127,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2022 (Reclassified)*
|
|
|
|
|
|
|
|
Cash and bank balances
|
30
|
n.a
|
Performing
|
12m
ECL
|
123,329
|
-**
|
123,329
|
Trade receivables
|
29
|
A2
|
(i)
|
Lifetime ECL
|
6,332
|
-**
|
6,332
|
Other receivables
|
29
|
n.a
|
(i)
|
12m
ECL
|
4,126
|
-**
|
4,126
|
Amount due from joint
arrangement partners
(net)
|
29
|
n.a
|
(i)
|
12m
ECL
|
4,268
|
-**
|
4,268
|
Non-current other
receivables
|
29
|
n.a
|
(i)
|
12m
ECL
|
83,192
|
-**
|
83,192
|
|
|
|
|
|
|
|
|
** The amount is
negligible.
|
(i) For trade receivables, the
Group has applied the simplified approach in IFRS 9 to measure the
loss allowance at lifetime ECL. The Group determines the
expected credit losses on these items by using specific
identification, estimated based on historical credit loss
experience based on the past due status of the debtors, adjusted as
appropriate to reflect current conditions and estimates of future
economic conditions. Accordingly, the credit risk profile of
these assets is presented based on their past due status in terms
of specific identification.
As at 31 December 2023, total
trade receivables amounted to US$12.5 million (2022: US$6.3
million). The balance in 2023 and 2022 had been fully
recovered in 2024 and 2023, respectively.
The concentration of credit risk
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. Both customers have an A2
credit rating (Moody's).
All trade receivables are generally settled 30
days after sale date. In the event that an invoice is issued
on a provisional basis, the final reconciliation is paid within 3
to 14 days from the issuance of the final invoice, largely
mitigating any credit risk.
The Group recognises lifetime ECL
for trade receivables. The ECL on these financial assets are
estimated based on days past due, by applying a percentage of
expected non-recoveries for each group of receivables. As at
year end, ECL from trade receivables are expected to be
insignificant.
The Group measures the loss
allowance for other receivables and amount due from joint
arrangement partners at an amount equal to 12-months ECL, as there
is no significant increase in credit risk since initial
recognition. ECL for other receivables are expected to be
insignificant.
The credit risk on cash and bank
balances and CWLH trust fund is limited because counterparties are
banks with high credit ratings assigned by international credit
rating agencies.
The maximum credit risk exposure
relating to financial assets is represented by their carrying value
as at the reporting date.
*Certain 2022 comparative
information has been reclassified between line items. Please refer
to Note 50.
Liquidity risk
Liquidity risk is the risk that
the Group will not be able to meet all of its financial obligations
as they become due. This includes the risk that the
Group cannot generate sufficient cash flow
from producing assets, or is unable to raise further capital in
order to meet its obligations.
The Group manages its liquidity
risk by optimising the positive free cash flow from its producing
assets, on-going cost reduction initiatives, merger and acquisition
strategies, bank balances on hand and in case appropriate,
lending.
The Group's net loss after tax for
the year was US$91.3 million (2022: profit after tax of US$9.2
million). Operating cash flows before movements in working
capital and net cash used in operating activities for the year
ended 31 December 2023 was US$36.5 million and US$12.1 million
(2022: US$158.5 million and net cash generated of US$121.2 million)
respectively. The Group's net current asset remained positive
at US$37.9 million as at 31 December 2023 (2022: US$72.4
million).
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 (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 31 December 2023 was
US$200.0 million.
The Group is required to maintain
a parent company financial covenant of consolidated net debt below
3.5 times annual EBITDAX and to deliver the required information to
the RBL Banks on a timely basis. As at 31 December 2023, the
Company's financial covenant was 0.14.
The RBL imposes restrictions on
the ability of the Group to freely utilise the cashflows generated
by the borrowing base assets for purposes that are not connected
with the borrowing base assets or the RBL. It is therefore
necessary of the Group to maintain two separate cash pools, a) cash
balances within the RBL facility ("RBL Cash Pool") and b) cash
balances outside the RBL facility, which comprise cash held by the
entities that are not part of the RBL facility including the
corporate G&A, Malaysia Technical Office and Singapore, the
Vietnamese exploration assets and the previously non-operated
PenMal Assets (PM318 and AAKBNLP PSCs) ("Corporate Cash
Pool"). The distribution of cash out of the RBL Cash Pool is
allowed provided that certain tests are met, such as (i) the
maintenance of two quarters principal, interest and fees in a
separate debt service reserve account and (ii) the maintenance of
the minimum cash balance within the RBL Cash Pool.
On 6 June 2023, the Company
completed an equity fundraising, creating an additional 94,081,826
ordinary shares at GB£0.45 per share, which comprised of a placing
and subscription of 92,312,691 new ordinary shares to existing and
new institutional shareholders and a placing and subscription of
1,769,135 new ordinary shares to the Directors of the
Company. Total gross proceeds were US$53.1 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
GB£0.45 per share, to raise additional proceeds of up to EUR8.0
million2 (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.
In support of the equity
fundraising, the Company entered into an up to US$50.0 million
equity underwrite debt facility agreement with Tyrus. The
equity underwrite facility was reduced to zero as funds raised from
the equity fundraising exceeded US$50.0 million.
In addition, 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, being the amount in
excess of US$50.0 million, following a 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 31 December 2023.
Further details are disclosed in
the Going Concern section in Note 2.
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.
2 The open offer was quoted in Euro of 8.0 million to meet the
applicable regulation issued by the European Union regarding to the
quantum of open offer.
Derivative and non-derivative
financial liabilities
The following table details the
expected contractual maturity for derivative and non-derivative
financial liabilities with agreed repayment periods. The
table below is based on the undiscounted contractual maturities of
the financial liabilities, including interest, that will be paid on
those liabilities, except where the Group anticipates that the cash
flow will occur in a different period.