TIDMJSE
RNS Number : 6984N
Jadestone Energy PLC
06 June 2022
Jadestone Energy
2021 Full Year Results and Recommended Final Dividend
Announcement
6 June 2022-Singapore: Jadestone Energy plc (AIM:JSE)
("Jadestone" or the "Company"), an independent oil and gas
production company and its subsidiaries (the "Group"), focused on
the Asia-Pacific region, reports today its audited consolidated
financial statements (the "Financial Statements"), as at and for
the financial year ended 31 December 2021, and announces a
recommended final dividend of US 1.34 per share. Management will
host a conference call today at 9:00 a.m. UK time, details of which
can be found in the release below.
Paul Blakeley, President and CEO commented:
"In a little over five years, we have transformed Jadestone from
an exploration-led business into a leading independent Asia-Pacific
upstream company with a significant production base, and material
organic growth potential. We delivered 10% production growth in
2021, exiting the year at much higher rates, and have guided to a
further 36% increase in the current year. This was on the back of a
successful Montara activity programme and five months of initial
contribution from the Peninsular Malaysia assets acquired during
the year.
Our decision to remain unhedged has resulted in direct exposure
to increasing oil prices and premiums, which are largely a
consequence of structural under-investment in upstream capacity,
although the distressing events in Ukraine this year are also
having a clear impact. Our year-end 2021 cash position of c.US$118
million has continued to grow in the first half of 2022, with
pro-forma cash balances of US$180 million at end-May 2022, which
includes the proceeds for barrels lifted in May but not yet
received. This cash position, and our forecast cash generation,
places us in a strong position to execute our 2022 capital
programme, take advantage of any high-quality additional M&A
opportunities that we identify, and also to significantly increase
shareholder returns. We are recommending a final dividend of
US$6.25 million, a 25% increase on the second 2020 dividend, and we
intend to return up to US$100 million of cash to shareholders over
the next 12 months. This will be in the form of higher ordinary
dividends, share buybacks and/or tender offers, starting with the
recommended final 2021 dividend starting today. The actual level of
shareholder returns will be influenced primarily by future oil
pricing and premiums, as well as operational performance and
business development activity, both organic and inorganic, over
this period.
I'm very pleased to report that we have taken final investment
decision on the Akatara gas field development onshore Indonesia,
following necessary approvals by the Indonesian upstream regulator,
with first gas on track for H1 2024. We have also seen positive
signs of progress on Nam Du / U Minh in Vietnam, with potential end
users of gas production from the fields being directed by the
government to enter into commercial discussions with Jadestone.
Progress towards completion of the Maari deal remains slow, however
the New Zealand upstream regulator has confirmed that it has
recommenced processing our application and we continue to respond
promptly to any information requests, while working cooperatively
with OMV, the seller.
Production in the first five months of 2022 has been impacted by
the previously announced unplanned compressor outage at Montara and
a temporary shut-in of the non-operated assets in Malaysia due to
class recertification issues with the leased FPSO. As a result,
production in the first part of this year has averaged c. 15,700
boe/d, although in May we have seen production rates return closer
to 17,000 boe/d. We therefore still expect 2022 average production
to be within the 15,500 - 18,500 boe/d guidance range, with the
final outcome being influenced by ongoing activity to handle
increased gas volumes at Montara (which longer-term may result in
the installation of additional compression on the FPSO), the timing
for production re-start from the non-operated Malaysia assets, and
the outcome of the Stag infill drilling programme later this year.
It is worth noting that as we continue to look for ways to further
improve Montara performance, installing additional compression will
not only increase oil production, but also allow for more gas to be
reinjected into the Montara field, thereby reducing the amount
being flared. Our unit operating expense and capital expenditure
guidance are also unchanged at US$23.00-28.00/boe and US$90-105
million respectively.
We aim to marry further growth in our business with a focus on
addressing our greenhouse gas profile. In early June 2022 we
announced a commitment to Net Zero Scope 1 and 2 greenhouse gas
emissions from our operated assets by 2040. Further detail on our
asset decarbonisation pathways, with interim milestones, will be a
key aspect of 2023 workstreams and we will release more news on
this in due course. We believe that our corporate strategy is
well-suited to the energy transition, delivering essential energy
from existing discovered and producing fields, and as a responsible
operator with a demonstrable track record of delivering asset
performance to the highest standards, providing confidence to
sellers and host governments alike.
Paul Blakeley
EXECUTIVE DIRECTOR,
PRESIDENT AND CHIEF EXECUTIVE OFFICER
2021 SUMMARY
USD'000 except where indicated 2021 2020
---------------------------------------------- --------- ------------
Production, boe/d 12,545 11,438
Realised oil price, US$/boe(1) 74.34 44.79
Revenue(2) 340,194 217,938
Operating costs per barrel of oil equivalent
(US$/boe)(3, 5) 26.22 23.10
Adjusted EBITDAX(3) 157,948 62,582
Loss after tax (13,742) (60,178)(4)
Loss per ordinary share: basic & diluted
(US$) (0.03) (0.13)
Dividend per ordinary share (US ) 1.93 1.62
Operating cash flows before movement
in working capital 96,622 86,883
Capital expenditure 55,996 24,065
Outstanding debt(3) - 7,386
Net cash(3) 117,865 82,055
Operational and financial summary
l Full year production increased by 10% to 12,545 boe/d (2020:
11,438 bbls/d), in line with expectations and the guidance range.
The increase year-on-year was due to:
! The acquisition of the Peninsular Malaysia assets ("PenMal
Assets") which contributed 2,539 boe/d (based on five month's
production from closing on 1 August 2021 averaged over the full
year);
! Stag production being broadly flat year-on-year at 2,359
bbls/d in 2021 (2020: 2,394 bbls/d); and
! Montara production declining to 7,647 bbls/d (2020: 9,045
bbls/d), as natural field decline, downtime during the 2021
activity programme and an unplanned shutdown to replace critical
defective valves offset the initial contribution from the
successful H6 infill well;
l Revenue increased 56% to US$340.2 million (2020: US$217.9
million), a Group record, due to a 66% increase in realised prices
and a 10% increase in lifted volumes;
l Jadestone's average realised price in 2021 was US$74.34/bbl
(2020: US$44.79/bbl), a 66% increase year-on-year. Average realised
prices included an average premium over benchmark Dated Brent of
US$3.39/bbl (2020: US$4.17/bbl);
Total lifted volumes for 2021 were aligned with production and
increased 10% to 4.6 mmboe (2020: 4.2 mmbbls). A total of 17
liftings (2020: 10) were achieved, including seven liftings for a
total of 0.6 mmbbls and an additional 6 12 mcf of gas (equivalent
to 0.1 mmboe) from the PenMal Assets;
l Total production costs of US$206.5 million, significantly
higher from US$105.3 million in 2020, in large part due to the
contribution of the PenMal Assets of US$24.5 million, plus, the
exceptional Skua well workovers programme of US$47.2 million,
normal well workovers at Stag and Montara of US$19.8 million (2020:
US$21.7 million) and increased repairs and maintenance ("R&M")
following Project Clover of US$40.1 million (2020: US$22.5
million);
l Adjusted annualised unit operating costs(5) for 2021 were
US$26.22/boe, within the guidance range, but up 14% from
US$23.10/bbl in 2020, primarily due to higher routine R&M and
lower production at Montara;
l Adjusted EBITDAX improved 152% to US$157.9 million compared to
US$62.6 million in 2020, predominately due to higher average
realised prices in 2021 and the contributions from PenMal Assets
since 1 August 2021;
l Net loss after tax of US$13.7 million (2020: US$60.2 million
loss after tax), reflecting the Skua workover costs at Montara and
higher R&M expenses at both Stag and Montara. During 2020, the
net loss was due to lower realised prices and the US$50.5 million
impairment of the SC56 licence offshore Philippines;
l Despite the Skua workovers, operating cash flow generation in
2021 was strong at US$96.6 million, before movements in working
capital, up 11% compared to 2020 of US$86.9 million ;
l Capital expenditure of US$56.0 million (2020: US$24.1 million)
up 133% year-on-year, primarily due to the drilling of the H6
infill well at Montara;
l Total 2021 major spending (capital expenditure and the Skua-10
& 11 workovers), of US$1 03.2 million, within the guidance
range;
l Cash balances of US$117.9 million at 2021-year end, 32% higher
compared to 2020 at US$89.4 million, benefitting from favourable
realised prices in the second half of the year. Jadestone has been
debt free following the final scheduled repayment of the Group's
senior debt facility in Q1 2021;
l Proven and probable reserves at year-end 2021 totalled 44.7
mmboe, a 20% increase on the end-2020 figure of 37.1 mmbbls,
reflecting the addition of the PenMal Assets offset by production
during the year; and
l Recommended final dividend of US 1.34/share , equivalent to a
distribution of US$ 6.3 million. This results in total dividends of
US$ 9.0 million in respect of 2021.
Business development
l Completion of the acquisition of PenMal Assets from SapuraOMV
on 1 August 2021, for a total cash consideration of US$20.0
million, comprising a headline price of US$9.0 million plus
adjustments of US$11.0 million . With an economic effective date of
1 January 2021, and taking into account cash received on
completion, the Group received a cash amount of US$9.2 million at
closing, net of the US$20.0 million due to SapuraOMV. In January
2022, a further US$3.0 million was paid in recognition of a
contingent payment triggered by Dated Brent averaging above
US$65/bbl for 2021;
l On 24 November 2021, the Group executed a settlement and
transfer agreement with DP Hexindo Gemilang Jaya to acquire the
remaining 10% interest in the Lemang PSC, for US$0.5 million and a
waiver of unpaid amounts related to the PSC. The transfer is
subject to customary approvals and is expected to complete in the
third quarter of 2022;
l Jadestone's internal reorganisation completed on 23 April
2021, with Jadestone Energy plc becoming the parent company of the
Group ; and
l Work continued to try to close the Maari acquisition in
parallel with the New Zealand Government's legislative changes to
the Crown Minerals Act. Both the seller and Jadestone remain fully
committed in trying to close the transaction as soon as
possible.
2022 GUIDANCE
l Announced a commitment to Net Zero Scope 1 and 2 greenhouse
gas ("GHG") emissions from Jadestone's operated assets by 2040;
l Production guidance of 15,500-18,500 boe/d maintained, which
excludes any contribution from the pending Maari acquisition. The
outcome will be determined by work to address current gas handling
constraints at Montara, the timing of return of the Malaysia
non-operated assets which have been offline since earlier this
year, and the impact of the Stag infill programme in the second
half of the year;
l 2022 guidance for unit operating costs (US$23.00 - 28.00/boe)
and capital expenditures (US$90.0 - 105.0 million) maintained;
l Further inorganic growth opportunities in the Asia-Pacific
region under active evaluation;
l Intention to return up to US$100.0 million of cash to
shareholders over the next 12 months, in the form of ordinary
dividends (including the final recommended 2021 dividend announced
today), share buybacks and/or tender offers. The actual level of
shareholder returns will be influenced primarily by future oil
pricing and premiums , operational performance and business
development activity over this period.
(1) Realised price represent the actual selling price, before
any impact from hedging.
(2) Revenue in 2020 included hedging income of US$31.4 million,
pursuant to the characterisation of the two-year capped swap
programme as a cash flow hedge under IFRS 9 Financial Instruments.
Losses realised from the 2021 swaps of US$4.6 million were
recognised in other expenses, pursuant to the characterisation of
the ad hoc 2021 six-month swap programme as derivative instruments
measured at fair value through profit or loss. The 2021 swap
programme covered a short time span (not exceeding a half yearly
reporting period), whereas the capped swap programme crossed three
annual reporting periods.
(3) Operating costs per boe, adjusted EBITDAX, outstanding debt
and net cash are non-IFRS measures and are explained in further
detail below.
(4) Loss after tax for 2020 included an impairment of US$50.5
million associated with capitalised intangible exploration costs at
SC56, a deep-water exploration block associated with the previous
management.
(5) Unit operating costs per barrel of oil equivalent before
workovers and movement in inventories but including net lease
payments and certain other adjustments (see non-IFRS measures
below).
Jadestone Energy plc.
Paul Blakeley, President and CEO +65 6324 0359 (Singapore)
Phil Corbett, Investor Relations Manager + 44 7713 687 467 (UK)
ir@jadestone-energy.com
Stifel Nicolaus Europe Limited (Nomad, +44 (0) 20 7710 7600
Joint Broker) (UK)
Callum Stewart / Jason Grossman / Ashton
Clanfield
Jefferies International Limited (Joint +44 (0) 20 7029 8000
Broker) (UK)
Tony White / Will Soutar
Camarco (Public Relations Advisor) +44 (0) 203 757 4980
(UK)
Billy Clegg / Georgia Edmonds / James jadestone@camarco.co.uk
Crothers
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.
Conference call and webcast
The management team will host an investor and analyst conference
call at 9:00 a.m. (London), 4:00 p.m. (Singapore) today, Monday, 6
June 2022, including a question and answer session.
A live webcast of the presentation will be available at the
below link. Dial-in details are provided below. Please register
approximately 15 minutes prior to the start of the call.
The results for the period ended 31 December 2021 will be
available on the Company's web site at:
www.jadestone-energy.com/investor-relations/ .
Webcast link:
https://produceredition.webcasts.com/starthere.jsp?ei=1549084&tp_key=81f0d2a39b
Event title: Jadestone Energy Full-Year 2021 Results
Time: 9:00 a.m. (UK time) / 4:00 p.m. (Singapore time)
Date: 6 June 2022
Conference ID: 23923977
Dial-in number details:
Country Dial-In Numbers
United Kingdom 08006522435
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Australia 1800076068
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Canada (Toll free) 888-390-0546
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France 0800916834
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Germany 08007240293
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Hong Kong 800962712
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Indonesia 0078030208221
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Japan 006633812569
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Malaysia 1800817426
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Netherlands 08000227908
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New Zealand 0800453421
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Singapore 8001013217
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Spain 900834776
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Sweden 0200899189
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Switzerland 0800312635
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United States (Toll free) 888-390-0546
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DIVID
On 6 June 2022, the Directors recommended a final 2021 dividend
of 1.34 US cents/share, equivalent to 1.07 GB pence/share based on
the spot exchange rate of 0.7954, an increase of 25% compared to
2020 and equivalent to a total distribution of US$9.0 million in
respect of 2021. The dividend will be paid on a gross basis, in US
dollars. The timetable for the dividend payment is as follows:
l Ex-dividend date : 16 June 2022
l Record date: 17 June 2022
l Payment date: 5 July 2022
The Company's growth-oriented strategy remains unchanged; the
business model is highly cash-generative, and, as a result, is
fundamentally pre-disposed to providing cash returns, after
allowing for organic reinvestment needs, whilst maintaining a
conservative capital structure, and not unduly limiting options for
further inorganic growth. The Company intends to maintain and grow
the dividend over time, in line with underlying cash flow
generation. The Company does not offer a dividend reinvestment plan
and does not offer dividends in the form of ordinary shares.
The Group's robust financial position at the end of 2021 has
strengthened further in 2022, with pro-forma cash balances of
US$180.0 million at end-May 2022, which includes the proceeds for
barrels lifted in May but not yet received, and no debt. After
careful consideration and while remaining focused on the Group's
growth strategy, Jadestone's directors believe this cash position
allows for a significant increase in shareholder returns. As a
result, Jadestone intends to return up to US$100.0 million of cash
to shareholders over the next 12 months. This will be in the form
of higher ordinary dividends, share buybacks and/or tender offers,
starting with the recommended final 2021 dividend announced today.
The actual structure of shareholder returns has not been finalised,
while the final amount of shareholder returns will primarily depend
on oil pricing and premiums going forward, as well as operational
performance and business development activity, both organic and
inorganic.
ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG")
As a leading oil and gas development and production company in
the Asia-Pacific region, Jadestone sees an opportunity to
contribute to the energy security of the region whilst striving to
deliver sustainable value for all of its stakeholders in a safe, as
well as environmentally and socially responsible, manner . The
Company's primary focus is the acquisition of mid-life producing
assets and, through additional capital investment, maximising
reserves recovery, improving operating performance and reducing
environmental impacts, including GHG emissions. Mitigating GHG
emissions from its upstream operations is a key pillar of
Jadestone's strategy and of its approach to managing the climate
risk exposure of the business.
The Group has committed to achieving Net Zero Scope 1 and 2 GHG
emissions from its operated assets by no later than 2040.
A key element of the Net Zero commitment will be the development
of an emissions reduction roadmap for major operated assets, which
will inform the interim emission reduction targets for the Group,
to be published by the end of 2023. Where feasible, the Net Zero
roadmap will prioritise actions aimed at reducing upstream
emissions in the near-term.
Environment
Jadestone proactively manages environmental impacts associated
with its operations through robust environmental management systems
that focus on minimising pollution and protecting water resources
whilst reducing carbon footprint from its upstream activities.
Despite continual challenges presented from the global pandemic
in 2021, Jadestone's maintained operational performance across most
areas of environmental impacts, with zero reportable environmental
incidents and no environmental high potential incidents recorded
during the reporting period at its operating facilities in
Australia. In 2021, Jadestone continued looking for ways to further
improve its discharge quality streams. The target of combined
oil-in-water ("OIW") concentrations across Stag and Montara to be
less than 14mg/litre was achieved and exceeded, with combined OIW
at 10mg/litre based on daily averages.
Mitigating GHG emissions from upstream operations is a key
pillar of Jadestone's strategy and of its approach to managing the
climate risk exposure of the business. Overall, 2021 Scope 1 GHG
emissions from the Australian assets increased by 6%, when compared
to 2020, against a target of 5% reduction. This increase was driven
by the performance of the Montara asset. Volumes flared at Montara
increased due to downtime in the gas reinjection system resulting
from unplanned failure to auxiliary parts as well as production
impacts resulting from drilling rig mobilisation. The latter led to
extended periods of time where Montara operations had to be either
fully shut in or had partial production, without associated gas
re-injection. These events have been subject to thorough review to
inform mitigation steps in the future.
In July 2021, Jadestone completed its acquisition of the PenMal
Assets, adding two operated and two non-operated assets to its
portfolio. Jadestone worked with the previous operator, as well as
the upstream arm of PETRONAS, to ensure that sound HSE and asset
integrity practices were sustained throughout the transition period
and were further built upon following the transfer of operatorship.
Going forward, Jadestone will continue to imprint its operational
excellence ethos onto the new assets, work to reduce GHG emissions,
manage water resources, maintain asset integrity and avoid major
accidents. Jadestone's 2022 sustainability reporting will reflect
the operational performance of the PenMal Assets.
Social
Jadestone strives to create a safe and rewarding working
environment for its workforce and goes beyond this to recognise the
positive impacts the Company can make within the local
communities.
Jadestone continued growing its asset base throughout 2021,
which is reflected in permanent employee numbers for the year
increasing by 60%. The Company welcomed 108 new permanent and
fixed-term employees as a result of the PenMal Assets acquisition
in August 2021, with the majority of the offshore and supply base
personnel engaged on the assets by the previous operator retained
as Jadestone employees, while new hires were also added to the
onshore team. Jadestone has a clear focus on attracting and
retaining local talent across its operations, resulting in 92% of
Jadestone workforce representing its local country of
operations.
Over the course of 2021, Jadestone's recorded three notable
personal injury incidents across its operated assets offshore
Australia. These personal injury events are very significant for
the Company, as protection of its employees is of paramount
importance. The injuries were managed in accordance with the
Company's Injury & Illness Management procedure and were
carefully investigated, with key learnings identified. In the
context of these incidents, the rolling monthly Total Recordable
Incident Frequency Rate ("TRIFR") increased accordingly and was
above target for the year. Stress factors and longer shift
patterns, created by uncertainty in a COVID-restricted world, were
likely contributory factors and the company has largely addressed
this returning to normal rosters.
In 2021, the Group enhanced community engagement programmes in
all countries of operations, increasing its investment five-fold
compared to the previous year, delivering tangible outcomes for the
communities, which have been detailed further in Jadestone's 2021
Sustainability Report.
Governance
Jadestone's ability to create long-term value for its
stakeholders is a key measurement of successful corporate
governance, underpinned by high standards of business ethics and
commitment to compliance. Appropriate governance is also about
ensuring that the most material ESG impacts and opportunities can
be acted upon, and proactively managed throughout the organisation,
with the tone set by the Board of Directors (the "Board").
Jadestone's Board updated its Board Charter and committee terms
of reference throughout 2021 to reflect the increasing importance
of Board-level oversight over climate and wider ESG-related risks
and opportunities. The Group had no incidents of violations of
anti-bribery and anti-corruption laws in 2021 and has continued to
maintain focus on timely regulatory approvals for new operations
and growth projects, evidenced by securing gas sales agreement for
the Akatara gas development in Indonesia, a key commercial
milestone for the project.
Task Force on Climate-Related Financial Disclosures ("TCFD")
Throughout 2021, the Company has continued to implement the TCFD
recommendations in its reporting and programmes, with a particular
focus on climate risk integration and strategy considerations,
commissioning a third-party to assist with conducting a climate
scenario analysis across its portfolio, as well as to map out Net
Zero strategic options. The Company's first climate scenario
analysis helped explore potential effects of climate change on the
business, corporate strategy and financial performance, by
modelling the possible changes to the price of hydrocarbons due to
the energy transition, and the impact of tighter carbon-related
regulations through additional carbon costs associated with the
International Energy Agency's climate scenarios. The results
suggest that whilst some negative impact on the Company's operating
cash flow would be observed, particularly in the longer-term, the
Company portfolio and business strategy remains resilient. The
detail of the climate scenario analysis is set out in the Company's
2021 Sustainability Report.
Jadestone's 2021 Sustainability Report is published alongside
the 2021 Annual Report. It details the Group's approach to ESG and
its performance across key focus areas for the 2021 calendar year,
as well as commitments to further improvements in 2022.
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 a 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 2021, the Montara assets had proven plus
probable reserves of 20.9mm barrels of oil, 100% net to
Jadestone.
The fields produce light sweet crude ( 42(o) 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
2021 ranged between US$0.43/bbl to US$2.94/bbl. Premiums have
increased in the first half of 2022, with the latest Tapis Brent
differential at around US$6.47/bbl.
By late September 2021, the H6 infill development well had been
successfully drilled and tied into the Montara field facilities and
production commenced. The well includes a circa 1,200 metre
horizontal section of the reservoir in good quality oil-bearing
sands. The well delivered an initial rate, after clean-up,
approaching 10,000 bbls/d.
Following the completion of the H6 well, two subsea workovers on
Skua-10 and 11 were performed with Skua-10 returning to stabilised
production of 1,500 bbls/d. The return of production for Skua 11
was delayed to March 2022 due to required repairs on the subsea
hydraulic connection, which were successfully achieved, and the
well was brought back on-stream with stabilised production of 1,500
bbls/d.
Montara production averaged 7,647 bbls/d in 2021 (2020: 9,045
bbls/d). Lower production was the result of natural field decline
and additional downtime associated with the drilling of H6 and the
subsea workovers of Skua 10 and 11, plus an unscheduled shutdown in
early 2021 to replace defective valves on the FPSO.
There were six liftings in 2021, resulting in total sales of 3.0
mmbbls, compared to 3.2 mmbbls in 2020 from the same number of
liftings.
As part of Montara's three-to-four-year regular maintenance
shutdown schedule, a three-week planned shutdown was originally
planned for July 2022. The key workstream during this planned
shutdown was the replacement of the gas turbine core, which was
moved forward to February/March due to the compressor outage
earlier in the year. As a result, the work scope of the planned
shutdown has been significantly reduced, and all remaining critical
maintenance activities can be carried out by a shorter one-week
turn-around which has now been scheduled for later in 2022.
Rescheduling has the added advantage of avoiding competition for
labour during the Australian offshore maintenance season, and a
shorter shutdown allows for maximised oil production while oil
price and premiums remain high. A small amount of carry-over work
may result from this but to be clear, none of this will impact on
the integrity or safety of the Montara assets.
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 2021, the field contained total proved plus
probable reserves of 12.6mm barrels of oil, 100% net to
Jadestone.
The Stag oilfield produces heavier sweet crude ( 18(o) API,
0.14% mass sulphur), which historically sells at a premium to Dated
Brent. The premium in 2021 ranged between US$8.30/bbl to
US$13.88/bbl. The most recent lifting was agreed at a premium of
US$23.72/bbl.
During 2021, the under-buoy hose, which is used for crude oil
off-loading was replaced, an undertaking which is scheduled to
occur only once every five years. In addition, two extra well
workovers were performed during the year compared to average, which
partially reflects the clearing of a backlog of workovers which had
built up in the early stages of the COVID-19 pandemic.
Production was maintained at 2,359 bbls/d in 2021, compared to
2,394 bbls/d in 2020, through ongoing production optimisation
despite the constraints of the COVID-19 pandemic on workover
execution.
There were four liftings in 2021, for total sales of 1.0 mmbbls,
compared to 0.9 mmbbls in 2020 from the same number of
liftings.
A once-in-every-three-years routine shut down was conducted in
Q2 2022 to perform pressure vessel inspections. In Q3 2022, the 50H
and 51H infill development wells are scheduled to be drilled. These
development wells are anticipated to complete and come onstream in
Q4 2022, and are expected to add around 1,000 bbls/d to current
production levels.
Malaysia
Operated: PM 323 and PM 329 PSCs & Non-operated: PM 318 and
AAKBNLP PSCs
On 1 August 2021, Jadestone completed the acquisition of the
entire share capital of SapuraOMV Upstream (PM) Inc., for a cash
consideration of US$20.0 million, comprising the headline price of
US$9.0 million plus adjustments of US$11.0 million.
The economic effective date of the acquisition was 1 January
2021, meaning the Group was entitled to the net cash generated
since 1 January 2021 up to the completion date. As a result, on 1
August 2021 the Group obtained gross cash held by SapuraOMV of
US$29.2 million, resulting in a net cash receipt of US$9.2
million.
There are two separate potential contingent payments of US$3.0
million each related to the annual average Dated Brent price
exceeding US$65/bbl in 2021 and US$70/bbl in 2022. Dated Brent
averaged US$70.91/bbl in 2021 and as a result the first US$3.0
million contingent payment was paid in January 2022. Management
believes the second contingent payment is probable and thus
recognised a discounted provision of US$1.4 million in the annual
financial statements for the year ended 31 December 2021.
Post completion the name of the acquired entity was
subsequentially changed to Jadestone Energy (PM) Inc.
The PenMal Assets consist of four licences, two of which are
operated by the Group. The two operated licences comprise a 70%
interest in the PM329 PSC, containing the East Piatu field, and a
60% interest in the PM323 PSC, which contains the East Belumut,
West Belumut and Chermingat fields. Both PSCs are located
approximately 230km northeast of Terengganu in shallow water. All
fields are in production and have been developed by way of fixed
wellhead and central processing platforms. The two non-operated
licences consist of 50% working interests in each of the PM318 PSC
and in the Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields
("AAKBNLP") PSC. The two non-operated PSCs are located in the same
region as PM329 and PM323.
The PenMal Assets added immediate cash flow from 6,057 boe/d, on
a net working interest basis, of which over 89% is oil. The PenMal
Assets produce light sweet crude that is blended to Tapis grade (43
(o) API, 0.04% mass sulphur).
The PenMal Assets added 11.2 mmboe net working interest 2P
reserves to the Group's 2P reserves as at 31 December 2021.
The Group believes there is scope to add incremental value to
the PenMal Assets in the near-term through both reservoir
optimisation, and production optimisation/enhancement activities
across the PM323 and PM329 operated licences. Gas reinjection is
expected to be a key part of reservoir optimisation. Production
enhancement has been initially focused on restoring idle wells to
production, while ongoing production optimisation is focused on
both gas lift and topsides processes. In addition, there are infill
development well opportunities at the West Belumut and East Piatu
fields, which will be evaluated in parallel with the East Belumut
infill potential.
In 2021, average production from the PenMal Assets since the
completion date was 5,377/bbls/d of oil and 4,084 mscf/d of gas
(for a total of 6,057 boe/d), net to Jadestone's working interest.
Averaged over the full year this is equivalent to 2,539 boe/d, net
to Jadestone. The average realised crude oil price was
US$78.29/bbl, while gas sold for US$2.19/mcf. The average premium
in 2021 ranged between US$0.27/bbl to US$3.46/bbl. The most recent
lifting was agreed at a premium of US$4.33/bbl.
Between the date of acquisition and the year end there were
seven liftings resulting in total sales of 582,181 boe and gas
sales of 624.8 mcf.
On 7 February 2022, the Bunga Kertas FPSO, deployed at the
non-operated assets, had its class suspended, resulting in the
fields having to shut in and temporarily cease production. The
operator anticipates the FPSO will have its class reinstated by
July/August 2022. Since the class suspension there has been no
production from the non-operated assets.
Pending acquisition
New Zealand
Maari project
On 16 November 2019, the Group executed a sale and purchase
agreement with OMV New Zealand Limited ("OMV New Zealand"), to
acquire an operated 69% interest in the Maari project, located 120
km offshore New Zealand, in a water depth of 100 metres, for a
total headline cash consideration of US$50.0 million and subject to
customary closing adjustments.
The transaction has achieved several key milestones with regard
to regulatory approvals, and the Group continues to focus on
securing the remaining ministerial consents from the New Zealand
Government, including the approval for transfer of
operatorship.
Jadestone and OMV New Zealand continue to work towards
completion of the transaction. The Group would assume the
operatorship of the Maari project upon completion of the
transaction. The economic benefits from 1 January 2019 until the
closing date will be adjusted in the final consideration price.
This is anticipated to be a net receipt to the Group.
Pre-production Assets
Indonesia
Lemang PSC
The Lemang PSC is located onshore Sumatra, Indonesia. The PSC
contains the Akatara field, which has been substantially de-risked
with 11 wells drilled into the structure, plus three years of oil
production history, up until the field ceased oil production in
December 2019.
On 30 June 2021, the Minister of Mines and Energy of Indonesia
issued a Ministerial decree that facilitates the development and
commercialisation of the Akatara gas field, allocating gas sales
from the gas field in the Lemang PSC to a subsidiary of PT
Perusahaan Listrik Negara, the national electricity utility, and
the associated production and sales of LPG to the local domestic
market in Jambi province, together with condensate sales to a local
buyer. On 1 December 2021, a gas sale agreement was signed between
Jadestone and PT Pelayanan Listrik Nasional Batam, as buyer.
In early 2022, Jadestone launched a tender for the engineering,
procurement, construction and installation contractor ("EPCI") for
the Akatara development. After a rigorous process, a recommendation
on the EPCI contractor was made to the Indonesian upstream
regulator, SKKMigas, in May 2022. Regulatory approval was received
in late May 2022 and the EPCI contract signed in early June 2022,
allowing Jadestone to take a final investment decision ("FID") and
accelerate development activity on the Akatara field.
The Akatara gas field has been independently estimated to
contain a 2C gross resource (pre local government back-in rights)
of 63.7 bcf of sales gas, 2.5 mmbbls of condensate and 5.6 mmboe of
LPG, equating to a combined 18.7 mmboe of resource, or 16.8 mmboe
net to Jadestone's existing 90% working interest. Following FID,
Jadestone will book it's share of economic Akatara gas resources at
the end of 2022.
Jadestone is pursuing a low-cost development of the field,
including efficient re-use of existing wells and infrastructure,
thereby minimising incremental impact on the local environment. The
Akatara gas project remains on track for first gas in H1 2024.
On 24 November 2021, the Group announced the acquisition,
subject to customary approvals, of the remaining 10% interest in
the PSC from PT Hexindo Gemilang Jaya ("Hexindo"). Through this
transaction, the Group's interest in the Lemang PSC will increase
to 100%, pre local government back-in rights. In return for the
transfer of Hexindo's 10% stake, the Group will waive unpaid
amounts related to Hexindo's interest in the Lemang PSC and will
pay a consideration of US$0.5 million (inclusive of transfer taxes)
subject to the approval of government, shareholders of Hexindo and
the shareholders of Eneco Energy Limited, Hexindo's parent company.
Jadestone anticipates receiving the remaining approvals in Q3
2022.
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 waters 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 2C resources of 93.9 mmboe.
The Tho Chu discovery in Block 51 is currently under suspended
development area status, with the exploration period expiring in
June 2023.
The formal field development plan ("FDP") in respect of the Nam
Du/U Minh development was submitted to the Vietnam regulatory
authorities in late 2019. The Group deferred the project in
mid-March 2020, amid delays in Vietnamese Government approvals and
the drop in global oil prices due to COVID-19.
Discussions are continuing with the Vietnamese Government and
Petrovietnam to reinstate the project, agree a gas production
profile for the development, as a precursor to a gas sales
contract, and ultimately attaining government sanction for the
field development.
Exploration Assets
Philippines
Service Contract 56 ("SC56")
In 2020, Total E&P Philippines B.V. ("Total") and Jadestone
informed the Philippines Department of Energy of their intention to
voluntarily surrender the entire interest in SC56 (Jadestone 25%
working interest) and accordingly, to terminate the contract. The
effective date of termination was 21 December 2020.
Following the termination, in Q3 2021, the Group paid US$1.5
million to the Philippines Department of Energy, related to the
unfulfilled minimum work programme, net to Jadestone's 25%
participating interest.
Service Contract 57 ("SC57")
In 2006, the Group executed an agreement with the Philippines
National Oil Company ("PNOC") to acquire a 21% working interest in
SC57. The acquisition required the approval of the Office of the
President of the Philippines and in December 2021 the Philippines
Department of Energy advised that such approval will not be granted
. The Group is now seeking reimbursement from PNOC for costs of
approximately US$0.9 million which it incurred in relation to a
2008 seismic acquisition campaign.
Reserves and resources
Total Proved plus Probable Reserves (net, mmboe)
============================================================================ =======
Australia(1) Malaysia(2,3,4) Indonesia Vietnam Total
Group
===================== ============= ================ ========== ======== =======
Opening balance, 31
December 2020 37.1 - - - 37.1
===================== ============= ================ ========== ======== =======
Acquisitions 0.0 12.5 - - 12.5
===================== ============= ================ ========== ======== =======
Technical revisions 0.1 0.9 - - 1.0
===================== ============= ================ ========== ======== =======
Production (3.7) (2.2) - - (5.9)
===================== ============= ================ ========== ======== =======
Ending balance, 31
December 2021 33.5 11.2 - - 44.7
===================== ============= ================ ========== ======== =======
As of 31 December 2021, the Group had proved plus probable oil
reserves ("2P reserves") of 44.7 mmboe, a 20% increase on the
end-2020 figure of 37.1 mmbbls. The primary driver of the increase
was the addition of 11.2 mmboe at year-end 2021 in respect of the
PenMal Assets acquisition during the year. The combined
year-on-year reduction in the reserves at Stag and Montara fields
reflected production during the year. ERCE Equipoise Limited
independently evaluated the Group's year-end 2021 reserves.
Total 2C Contingent Resources (net, mmboe)
===================================================================================
Australia Malaysia Indonesia(5) Vietnam(6) Total
Group
===================== =========== ========== ============= =========== =======
Opening balance, 31
December 2020 - - 16.8 93.9 110.7
===================== =========== ========== ============= =========== =======
Acquisitions - - - - -
===================== =========== ========== ============= =========== =======
Technical revisions - - - - -
===================== =========== ========== ============= =========== =======
Production - - - - -
===================== =========== ========== ============= =========== =======
Ending balance, 31
December 2021 - - 16.8 93.9 110.7
===================== =========== ========== ============= =========== =======
The Group's best case contingent resources ("2C resources") were
unchanged year-on-year at 110.7 mmboe. Of this figure, the Akatara
gas field development comprises 16.8 mmboe. The Group anticipates
that the Akatara gas field 2C resources will be converted to 2P
reserves following development sanction of the project.
Henning Hoeyland of Jadestone Energy plc., Jadestone's Australia
Country Manager, with a Masters degree in Petroleum Engineering who
is a member of the Society of Petroleum Engineers and who has been
involved in the energy industry for more than 20 years, has read
and approved the technical disclosure in this release.
(1) Proven and Probable Reserves for Jadestone's Australian
assets have been prepared in accordance with the Canadian Oil and
Gas Evaluation ("COGE") Handbook as the standard for classification
and reporting. Jadestone does not believe that there are
significant differences between the COGE standard and the 2018
guidelines endorsed by SPE, WPC, AAPG and SPEE Petroleum Resource
Management System.
(2) Proven and Probable Reserves for Jadestone's Malaysia assets
have been prepared in accordance with the 2018 guidelines endorsed
by SPE, WPC, AAPG and SPEE Petroleum Resource Management
System.
(3) Assumes oil equivalent conversion factor of 6,000
scf/boe.
(4) The acquired 2P Reserves in Malaysia are based on an
effective date of 1 January 2021. As such, the production figure of
2.2 mmboe in the table above reflects production over the calendar
year 2021. Jadestone's reported production for 2021 of 12,545 boe/d
includes production from the PenMal assets from the completion of
the assets (2 August 2021). The positive revision of 0.9 mmboe
reflects an extension of. economic life on the back of higher oil
prices.
(5) Lemang PSC 2C resources based on ERCE Competent Person's
Report effective 31 December 2020.
(6) Vietnam 2C resources 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 audited consolidated financial statements for the year
ended 31 December 2021.
USD'000 except where indicated 2021 2020
---------------------------------------------- ---------- ----------
Sales volume, barrels of oil equivalent
(boe) 4,562,279 4,165,612
Production, boe/d 12,545 11,438
Realised oil price, US$/boe(1) 74.34 44.79
Revenue(2) 340,194 217,938
Production costs (206,523) (105,338)
Operating costs per barrel of oil equivalent
(US$/boe)(3) 26.22 23.10
Adjusted EBITDAX(3) 157,948 62,582
Unit depletion , depreciation & amortisation
(US$/ boe ) 13.67 16.24
Impairment - 50,455
Profit/(Loss) before tax 1,080 (57,238)
Loss after tax (13,742) (60,178)
Loss per ordinary share: basic & diluted
(US$) (0.03) (0.13)
Dividend per ordinary share (US ) 1.93 1.62
Operating cash flows before movement
in working capital 96,622 86,883
Capital expenditure 55,996 24,065
Outstanding debt(3) - 7,386
Net cash(3) 117,865 82,055
Benchmark commodity price and realised price
The average benchmark price incorporated into the Group's
liftings was US$70.94/bbl in 2021, an increase of 75% compared to
2020 at US$40.61/bbl.
The actual average realised price in 2021 increased broadly in
line with the benchmark price, by 66% to US$74.34/bbl, compared to
US$44.79/bbl in 2020. The average premium for the year was
US$3.39/bbl, compared to 2020 of US$4.17/bbl. The decline in
premiums was predominately due to the inclusion of PenMal Assets
barrels with an average premium of $1.14bbl. Stag averaged
US$11.20/bbl (2020:11.45/bbl) and Montara US$1.14/bbl (2020:
US$2.04/bbl).
Since the December 2021 year end, premiums have continued to
increase with the most recent liftings achieving a premium of US$
6.47 /bbl, US$2 3.72/bbl and US$4.33/bbl, at Montara, Stag and
PenMal Assets respectively.
(1) Realised oil price represents the actual selling price and
before any impact from hedging .
(2) Revenue in 2020 included hedging income of US$31.4 million,
pursuant to the characterisation of the two-year capped swap
programme as a cash flow hedge under IFRS 9. Losses realised from
the 2021 swaps of US$4.6 million were recognised in other expenses,
pursuant to the characterisation of the ad hoc 2021 six-month swap
programme as derivative instruments measured at fair value through
profit or loss. The 2021 swap programme covered a short time span
(not exceeding a half yearly reporting period), whereas the capped
swap programme crossed three annual reporting periods.
(3) Operating cost per boe, adjusted EBITDAX, outstanding debt
and net cash are non-IFRS measures and are explained in further
detail below.
Production and liftings
The Group generated average production of 12,545 boe/d in 2021,
compared to 11,438 bbls/d in 2020. Production increased due to the
acquisition of PenMal Assets which generated average production of
6,057 boe/d since the date of acquisition, or 2,539 boe/d averaged
over the full year. Montara production declined in 2021 to 7,647
bbls/d from 9,045 bbls/d in 2020 due to natural field decline and
downtime associated with the drilling of H6 and workovers on Skua
10 & 11, plus an unscheduled shutdown to replace defective
valves on the FPSO. Stag production in 2021 was 2,359 bbls/d,
broadly in line with the 2,394 bbls/d achieved in 2020.
The Group had 17 liftings during the year (2020: 10), resulting
in sales of 4.6 mmbbls (2020: 4.2 mmbbls), reflecting the higher
production compared to 2020. The PenMal Assets contributed seven
oil liftings since August, representing 0.6 mmbbls. In addition,
PenMal Assets produced and sold 624.8 mcf (approximately 0.1 mmboe)
of natural gas, which is sold via pipeline directly to
PETRONAS.
Revenue
The Group generated revenue of US$340.2 million in 2021, an
increase of 56% compared to 2020 of US$217.9 million, and the
highest revenue ever recorded by the Group. The increase of
US$122.3 million was predominately due to:
-- Higher average realised prices in 2021, compared to 2020 for
Stag and Montara, contributing an additional US$115.3 million;
-- PenMal Assets generating oil revenues of US$45.6 million and
gas sales of US$1.0 million (2020: nil);
-- A decrease of 0.2 mmbbls in lifted volumes at Montara and
Stag in 2021 compared to 2020, resulting in a decline in revenues
of US$8.3 million; and
-- Hedging income was nil(1) in 2021, a decline of US$31.4
million compared to 2020. The Group's 24 month capped swap cash
flow hedge programme ended on 30 September 2020.
Production costs
Production costs increased by 96% in 2021 to US$206.5 million,
from US$105.3 million in 2020, predominately due to:
-- Workover costs of US$67.0 million (2020: US$21.7 million),
mostly related to the subsea workovers at Skua 10 & 11 of
US$47.2 million. The Montara subsea workovers were a one-off event
and differ from the pump replacements at Stag as they require a
dedicated drilling rig, whereas the Stag workovers are undertaken
by the hydraulic workover unit in place on the Stag platform. There
were nine workovers at Stag in 2021, compared to eight in 2020;
-- Repairs and maintenance costs of $45.2 million, compared to
US$22.5 million in 2020, with the PenMal Assets contributing US$5.1
million and Australia an additional of US$17.6 million compared to
2020. Montara incurred an additional US$11.6 million due to a
once-in-every-three-year subsea flowline inspection, a subsea
control module ("SCM") change-out on the Swift North well and
higher fabric maintenance costs. Stag incurred an additional US$6.0
million due to a once-in-every-five-years under-buoy hose
replacement and also higher fabric maintenance costs;
-- Operating costs increased to US$61.6 million (2020: US$45.2
million), with the PenMal Assets contributing US$11.2 million, plus
higher contractor charges at Stag and Montara from changing rosters
in response to COVID-19 restrictions;
(1) The hedging loss in 2021 of US$4.6 million was recognised
within other expenses, as opposed to offsetting against revenue,
due to the adoption of a different accounting treatment for the
2021 commodity swap contracts. The two-year capped swap programme
was characterised as a cash flow hedge under IFRS 9 and realised
gains were recognised as part of revenue. Losses realised from the
2021 swaps were recognised in other expenses, pursuant to the
characterisation of the ad hoc 2021 six-month swap programme as
derivative instruments measured at fair value through profit or
loss. The 2021 programme covered a short time span (not exceeding a
half yearly reporting period), whereas the capped swap programme
crossed three annual reporting periods.
-- Logistics costs increased to US$20.2 million (2020: US$18.9
million), with the PenMal Assets contributing US$2.3 million;
-- Transportation costs of US$2.8 million in 2021 (2020: nil),
reflecting the change in offtake arrangements at Stag following the
cancellation of the Dampier Spirit FSO lease in September 2020. The
revised offtake arrangements in Q4 2020 and through 2021 resulted
in a change to the point of sale, with end buyers predominately
located in Singapore and Malaysia, which resulted in the Group
paying transportation expenses; and
-- A net inventory movement of US$12.5 million (2021: US$9.7
million; 2020: credit of US$2.8 million), reflecting the
year-on-year differential of the Group's crude inventories on hand
and the change in net underlift/overlift position of the Group at
year end due to production imbalances with the joint operating
partner in the PenMal Assets. There were 274,103 bbls on hand at
2021 year end, compared to 601,999 bbls at 2020 year end,
contributing to US$9.0 million. Additionally, the Group has a net
underlift of 88,398 bbls from PenMal Assets at year end, compared
to 135,115 bbls on the acquisition date, contributing to US$3.5
million.
Unit operating costs per barrel of oil equivalent were
US$26.22/boe (2020: US$23.10/bbl), before workovers and movement in
inventories, but including net lease payments and certain other
adjustments (see non-IFRS measures below). Unit costs increased due
to the lower production at Montara and higher operating costs
including repairs & maintenance.
Depletion, depreciation and amortisation ("DD&A")
DD&A charges were US$80.2 million in 2021, compared to
US$84.6 million in 2020, reflecting lower production at Montara
during the year, resulting in a decrease in depletion charges in
Australia of US$9.0 million compared to 2020. The reduction was
partly offset by depletion charges at the PenMal Assets of US$3.6
million since the date of acquisition of 1 August 2021.
Depreciation of the Group's right-of-use assets declined by
US$5.0 million mostly due to the termination of the Dampier Spirit
leased FSO at Stag in 2020.
The depletion cost on a unit basis was US$13.67/boe in 2021
(2020: US$16.24/bbl), predominately due to the inclusion of PenMal
Assets which lowered the average DD&A unit charge. The combined
depletion cost on a unit basis at both Stag and Montara remained
largely comparable to 2020 (2021: US$16.16/bbl; 2020:
US$16.24/bbl). The PenMal Assets, by comparison, recorded unit
depletion charges of US$3.87/boe.
Staff costs
Total staff costs were US$51.8 million in 2021, comprising
US$26.8 million (2020: US$20.7 million) in relation to offshore
employees, which are recorded under production costs, and US$25.1
million (2020: US$21.9 million) associated with administrative
employees. The average number of employees employed by the Group
during the year was 278 (2020: 210), reflecting the additional
employees associated with the acquisition of the PenMal Assets.
Other expenses
Other expenses decreased in 2021 to US$26.2 million (2020:
US$26.9 million). The variance of US$0.7 million was predominately
due to:
-- Reduction of non-recurring costs by US$9.2 million compared
to 2020. In 2021, the Group incurred total non-recurring costs of
US$5.2 million, these included internal reorganisation costs of
US$1.1 million, acquisition costs of US$0.8 million in relation to
the PenMal Assets, and several other business development related
expenses of US$3.3 million. In comparison, the Group had a total of
US$14.4 million of one-off costs in 2020, including US$9.1 million
associated with the litigation fees in respect of SC56 and the exit
from the Block 05-1 PSC offshore Vietnam (see 'Other income'
section for the litigation income generated), Australian rig
contract deferral costs of US$3.0 million, Australian exploration
expense of US$1.0 million and several business development projects
totalling US$1.3 million, including the acquisition of the Lemang
PSC ;
-- Net foreign exchange loss of US$1.0 million (2020: US$2.6 million);
-- A fair value loss on commodity swaps of US$4.6 million (2020:
US$0.5 million) pursuant to the characterisation of the ad-hoc 2021
six-month swap programme as derivative instruments measured at fair
value through the profit and loss;
-- Written off of intangible exploration assets of US$5.3
million (2020: nil) following the termination of a contract with a
third-party contractor; and
-- Higher provision made for slow-moving materials and spares on
hand of US$2.6 million (2020: US$0.1 million), mainly associated
with the Australian drilling components and facility spare
parts.
Other income
Other income of US$7.7 million was generated during 2021
compared to 2020 of US$26.4 million. The income is predominately
the result of non-recurring transactions as detailed below:
-- During 2021, the Group incurred US$2.5 million of net foreign
exchange gains (2020: US$ 0.1million) associated with the weakening
of the Australian dollar;
-- Rebate income of US$4.5 million (2020: US$3.6 million)
arising from the sublease of right-of-use assets under the Group's
helicopter lease contract;
-- In comparison, during 2020, the Group generated US$11.1
million of litigation income from Total regarding the carried
exploration well at SC56 for US11.1 million and received a
settlement sum of US$1.0 million from Inpex regarding the
litigation resolution of Block 05-1 (see 'Other expenses' section
for the litigation fees incurred); and
-- Also, 2020 saw the reversal of provisions associated with the
Dampier Spirit of US$6.4 million and a fair value gain on
derivatives of US$3.8 million.
Impairment
In 2020, the Group recorded an impairment of US$50.5 million
associated with the capitalised intangible exploration costs at
SC56, as the costs were no longer deemed recoverable, following the
decision to voluntarily relinquish the Group's interest in the
block. The impairment provision was formally written off during
2021 following the finalisation of the settlement for unfulfilled
minimum work commitments under the PSC for US$1.5 million, payable
to the Department of Energy in the Philippines. The penalty was
offset against a prior provision of US$1.8 million resulting in a
credit to other income of US$0.3 million.
Taxation
The tax charge of US$14.8 million in 2021 (2020: US$2.9 million)
is split between a current tax charge of US$7.3 million (2020:
US$11.7 million) and a deferred tax charge of US$7.5 million (2020:
credit US$8.7 million). The current tax charge includes US$9.5
million (2020: nil) of PITA tax incurred by the Malaysian
operations, offset by an Australian PRRT refund of US$1.4 million
(2020: US$1.7 million paid) and corporate tax credit of US$0.8
million (2020: US$10.0 million expense).
Australian PRRT
Australian petroleum resource rent tax ("PRRT") is a cash-based
tax charged at the rate of 40% and is deductible from income tax.
The current tax credit of US$1.4 million is associated with Stag
operations, due to the utilisation of PRRT carried forward losses
during the year. Montara is not anticipated to incur PRRT expense
in the future, as it has unutilised PRRT carried forward credits of
US$3.4 billion (2020: US$3.3 billion). Based on management's latest
forecasts, the augmentation on historical accumulated PRRT net
losses will more than offset PRRT that would otherwise arise on
future PRRT taxable profits.
Malaysian PITA
Malaysian petroleum income tax ("PITA") is charged for each year
of assessment derived from petroleum operations at the rate of 38%.
The current tax charge represents the tax liability generated from
the date of acquisition until the year end.
Deferred tax
The deferred tax movement during the year reflects timing
differences for income tax, PITA and PRRT. The Group incurred a
deferred tax charge of US$7.5 million in 2021, which consists of
US$5.2 million for the recognition of net deferred tax liabilities
on the Australian operations, US$3.4 million of deferred PRRT
expense and US$1.1 million of deferred PITA credit. In 2020, the
Group had a deferred tax credit of US$8.7 million, which consisted
of US$4.0 million for the unwinding of deferred tax liabilities and
US$4.7 million of deferred PRRT credit . The increase in deferred
tax charge in 2021, compared to 2020, is explained by:
-- Additional deferred tax liabilities recognised at the
Australian operations, predominately arising from the additional
capital expenditure spent at Montara in 2021, which created
temporary taxable timing differences arising from the difference
between the accounting base and the tax base of oil and gas
properties, due to the immediate deductibility of the cost
associated with the H6 drilling program. The Group further
recognised deferred tax liabilities arising from the insurance
claim receivable of US$10.3 million on the well control claim for
the Skua 11 well workovers. The insurance claim will be taxable in
future following cash receipt ;
-- Deferred PRRT expense of US$3.4 million in 2021, arising from
the reduction of deferred tax assets associated with Stag PRRT,
following the utilisation of unutilised PRRT losses carried forward
from 2020; and
-- The Group incurred US$1.1 million of deferred PITA credit
predominately arising from the recognition of deferred tax assets
associated with the oil and gas properties based on the difference
between the accounting depletion charge and the tax charge in
2021.
2021 RECONCILIATION OF NET CASH
US$'000 US$'000
--------------------------------------------- ---------- ---------
Cash and cash equivalents, 31 December
2020 80,996
Restricted cash, 31 December 2020 8,445
----------
Total cash and cash equivalent, 31 December
2020 89,441
Revenue 340,194
Other operating income 6,030
Production costs (206,523)
Staff costs (24,117)
General and administrative expenses (18,962)
Operating cash flows before movements
in working capital 96,622
Movement in working capital 18,808
Net tax paid (11,834)
Interest paid (1,505)
Purchases of intangible exploration assets,
oil and gas properties, and
plant and equipment(1) (55,920)
Net cash inflows from acquisition of PenMal
Assets 9,219
Other investing activities 80
Financing activities (27,046)
---------
Total cash and cash equivalent, 31 December
2021 117,865
=========
Net cash increased over the year due to the combination of
higher realised prices and increased production due to the
acquisition of the PenMal Assets, partially offset by the drilling
of the H6 infill development well, spending on the Skua subsea
workovers and non-routine repairs and maintenance.
The Group has been debt free following the final repayment of
its reserves based loan in March 2021.
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 operating
cost per barrel of oil equivalent (opex/boe), adjusted EBITDAX,
outstanding debt, and net cash.
The following notes describe why the Group has selected these
non-IFRS measures.
(1) Total capital expenditure was US$56.0 million (2020: US$24.1
million), comprising total capital expenditure paid of US$55.9
million (2020: US$17.9 million), plus accrued capital expenditure
of US$0.1 million (2020: US$6.1 million).
Operating costs per barrel of oil equivalent (Opex/boe)
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.
Opex/boe is defined as total production costs excluding oil
inventories movement and underlift/overlift, write down of
inventories, workovers (to facilitate better comparability period
to period) and non-recurring repair and maintenance. It includes
lease payments related to operational activities, net of any income
earned from right-of-use assets involved in production, foreign
exchange gains arising from foreign exchange forwards in respect of
local currency operating expenditure, and excludes transportation
costs, PenMal Asset supplementary payments, DD&A and short-term
COVID-19 subsidies.
The adjusted production cost 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 2021 2020
Production costs (reported) 206,523 105,338
Adjustments
Lease payments related to operating activity(1) 10,619 17,548
Underlift, overlift and crude inventories
movement(2) (9,680) 2,806
Workover costs(3) (67,006) (21,686)
Impact from FX derivatives apportioned
to production costs(4) - (2,649)
Other income(5) (4,512) (3,634)
Non-recurring repair and maintenance(6) (6,593) (1,619)
Australian transportation costs (1,231) -
PenMal Assets supplementary payments(7) (8,255) -
Australian Government JobKeeper scheme 196 600
Adjusted production costs 120,061 96,704
----------- -----------
Total production (barrels of oil equivalent) 4,578,962 4,186,478
Operating costs per barrel of oil equivalent 26.22 23.10
=========== ===========
(1) Lease payments related to operating activities are lease
payments considered to be operating costs in nature, including
leased helicopters for transporting offshore crews, and the Dampier
Spirit FSO rental fees prior to its lease termination in September
2020. 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) A portion of the net impact from foreign exchange hedging
instruments was apportioned to production costs, based on the
Group's actual local currency expenditure during the hedging
period.
(5) Other income represents the rental income from a helicopter
rental contract (a right-of-use asset) to a third party.
(6) Non-recurring repair and maintenance costs in 2021 related
to the Montara Swift North SCM change out and facility integrity
baseline survey. The costs in 2020 related to costs associated with
Cyclone Damien.
(7) The supplementary payments are required under the terms of
PSCs based on Jadestone's entitlement to profit from oil and gas.
The payments are made to PETRONAS.
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 information 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, non-recurring expenses and exploration assets
write-offs.
The calculation of adjusted EBITDAX is as follow:
USD'000 2021 2020
Revenue 340,194 217,938
Production cost (206,523) (105,338)
Administrative staff costs (25,068) (21,903)
Impairment of assets - (50,455)
Other expenses (26,181) (26,918)
Other income, excluding interest income 7,602 26,119
Other financial gains 266 359
---------- ----------
Unadjusted EBITDAX 90,290 39,802
Non-recurring
Net loss/(gain) from oil price derivatives 4,633 (30,889)
Impairment of assets - 50,455
Non-recurring opex(1) 53,096 8,270
Intangible exploration assets written 5,260 -
off
Net litigation income - (3,005)
Rig contract deferred costs - 3,000
Loss/(gain) on contingent considerations 438 (359)
Gain from termination of FSO lease - (6,429)
Others(2) 4,231 1,737
---------- ----------
67,658 22,780
---------- ----------
Adjusted EBITDAX 157,948 62,582
========== ==========
The Group EBITDAX reflects the strong cash operational
performance of the assets with the creation of an additional US$1
58.0 million generated during 2021 before investing activities and
non-recurring operating costs.
(1) Includes one-off major maintenance/well intervention
activities, in particular the workover campaigns at Montara Skua 10
& 11, Swift North SCM change out and facility integrity
baseline survey in 2021. The 2020 one-off major maintenance/well
intervention activities were comprised of Skua 10 and H3 workover
campaigns, and other non-recurring production expenditures such as
the repair and maintenance costs associated with weather downtime
in 2020.
(2) Includes Maari transition team costs, Australian Government
JobKeeper scheme, business development and internal reorganisation
costs, as well as Montara seismic acquisition costs associated with
the non-licence area and gain on contingent consideration in
2020.
Outstanding debt
Total borrowings, as recorded in the Group's consolidated
statement of financial position, represents the carrying amount of
the Group's interest bearing financial indebtedness, measured at
amortised cost pursuant to IFRS 9 Financial Instruments.
Outstanding debt is a non-IFRS measure which does not have a
standardised meaning prescribed by IFRS. Management uses this
measure to manage the capital structure, and make adjustments to
it, based on the funds available to the Group. Outstanding debt is
defined as long and short-term interest bearing debt, with
effective interest method financing costs added back (i.e.,
excluded), and excluding derivatives.
As at 31 December 2021, the Group has no outstanding interest
bearing financial indebtedness of any kind, following the final
scheduled repayment of the RBL at the end of Q1 2021.
USD'000 2021 2020
----------------------------------------------- ---- -------
Long-term borrowing - -
Short-term borrowing - 7,296
Add back: effective interest method financing
costs - 1,021
---- -------
Outstanding debt - 7,386
==== =======
Net cash
Net cash is a non-IFRS measure which does not have a
standardised meaning prescribed by IFRS. Management uses this
measure to analyse the financial strength of the Group. This
measure is used to ensure capital is managed effectively in order
to support ongoing operations, and to raise additional funds, if
required.
USD'000 2021 2020
--------------------------- --------- ---------
Outstanding debt - (7,386)
Cash and cash equivalents 117,865 81,996
Restricted cash - 7,445
--------- ---------
Net cash 117,865 82,055
========= =========
Net cash is defined as the sum of cash and cash equivalents and
restricted cash, less outstanding debt. Cash and cash equivalents
in 2021 contain a restricted cash balance of US$0.4 million and
US$0.5 million in relation to a deposit placed for bank guarantee
with respect to the PenMal Assets and an Australian office
building, respectively. In 2020, restricted cash included the RBL
debt service reserve account balance of US$7.4 million but excluded
US$1.0 million in respect of a cash collateralised bank guarantee
with the Indonesian regulator with respect to a joint study
agreement as the guarantee is removable and can then be used to
fund the business. The Indonesian bank guarantee was released in Q3
2021 upon completion of the study.
CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE
INCOME
for the year ended 31 December 2021
2021 2020
Notes USD'000 USD'000
---------------------------------------------- ------- ----------- -----------
Revenue 5 340,194 217,938
Production costs 6 (206,523) (105,338)
Depletion, depreciation and amortisation 7 (80,215) (84,642)
Administrative staff costs 8 (25,068) (21,903)
Other expenses 11 (26,181) (26,918)
Impairment of assets 13 - (50,455)
Other income 14 7,682 26,376
Finance costs 15 (9,075) (12,655)
Other financial gains 16 266 359
----------- -----------
Profit/(Loss) before tax 1,080 (57,238)
Income tax expense 17 (14,822) (2,940)
----------- -----------
Loss for the year (13,742) (60,178)
=========== ===========
Loss per ordinary share
Basic and diluted (US$) 18 (0.03) (0.13)
=========== ===========
Consolidated statement of comprehensive
income
Loss for the year (13,742) (60,178)
Other comprehensive income
Items that may be reclassified subsequently
to profit or loss:
Gain on unrealised cash flow hedges 33 - 26,093
Hedging gain reclassified to profit
or loss 33 - (31,364)
----------- -----------
- (5,271)
Tax income relating to components
of other comprehensive
income 17 - 1,583
----------- -----------
Other comprehensive income - (3,688)
----------- -----------
Total comprehensive income for the
year (13,742) (63,866)
=========== ===========
All comprehensive income is attributable to the equity holders
of the parent.
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
(Company Registration Number: 13152520)
as at 31 December 2021
2021 2020
Notes USD'000 USD'000
----------------------------------- ------- --------- ---------
Assets
Non-current assets
Intangible exploration assets 21 93,241 100,670
Oil and gas properties 22 353,592 317,676
Plant and equipment 23 8,963 1,652
Right-of-use assets 24 13,852 23,673
Other receivables and prepayment 28 48,500 4,404
Deferred tax assets 26 25,278 19,727
--------- ---------
Total non-current assets 543,426 467,802
========= =========
Current assets
Inventories 27 23,299 45,361
Trade and other receivables 28 37,951 7,110
Tax recoverable 17 9,367 -
Restricted cash 29 - 8,445
Cash and cash equivalents 29 117,865 80,996
--------- ---------
Total current assets 188,482 141,912
--------- ---------
Total assets 731,908 609,714
========= =========
Equity and liabilities
Equity
Capital and reserves
Share capital 30 559 466,979
Merger reserve 32 146,270 -
Share-based payments reserve 34 25,936 24,985
Accumulated losses (31,692) (331,322)
--------- ---------
Total equity 141,073 160,642
--------- ---------
Non-current liabilities
Provisions 35 410,697 288,224
Lease liabilities 36 4,504 13,305
Tax liabilities - 26,896
Deferred tax liabilities 26 67,097 58,229
--------- ---------
Total non-current liabilities 482,298 386,654
========= =========
2021 2020
Notes USD'000 USD'000
----------------------------------- ------- -------- --------
Current liabilities
Borrowings 37 - 7,296
Lease liabilities 36 11,161 12,478
Trade and other payables 39 69,090 32,192
Provisions 35 1,947 4,558
Derivative financial instruments 40 - 471
Tax liabilities 26,339 5,423
-------- --------
Total current liabilities 108,537 62,418
-------- --------
Total liabilities
TOTAL EQUITY AND LIABILITIES 590,835 449,072
-------- --------
Total equity and liabilities 731,908 609,714
======== ========
The financial statements were approved by the Board of Directors
and authorised for issue on 3 June 2022. They were signed on its
behalf by:
A. Paul Blakeley
Director
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
for the year ended 31 December 2021
Share-based
payments
Share Merger reserve Hedging Accumulated
capital reserve USD'000 reserves losses Total
USD'000 USD'000 USD'000 USD'000 USD'000
--------------------- ---------- ---------- ------------ ----------- -------------- ----------
As at 1 January
2020 466,573 - 23,857 3,688 (268,651) 225,467
Loss for the
year - - - - (60,178) (60,178)
Other comprehensive
income for
the year - - - (3,688) - (3,688)
---------- ---------- ------------ ----------- -------------- ----------
Total comprehensive
income for
the year - - - (3,688) (60,178) (63,866)
---------- ---------- ------------ ----------- -------------- ----------
Dividend paid
(Note 31) - - - - (2,493) (2,493)
Share-based
compensation
(Note 8) - - 1,128 - - 1,128
Shares issued
(Note 30) 406 - - - - 406
---------- ---------- ------------ ----------- -------------- ----------
Total transactions
with owners,
recognised
directly in
equity 406 - 1,128 - (2,493) (959)
---------- ---------- ------------ ----------- -------------- ----------
As at 31 December
2020 466,979 - 24,985 - (331,322) 160,642
Loss for the
year,
representing
total
comprehensive
income for
the year - - - - (13,742) (13,742)
---------- ---------- ------------ ----------- -------------- ----------
Capital reduction
(Note 30) (467,387) 146,270 - - 321,117 -
Dividend paid
(Note 31) - - - - (7,745) (7,745)
Share-based
compensation
(Note 8) - - 951 - - 951
Shares issued
(Note 30) 967 - - - - 967
Total transactions
with owners,
recognised
directly in
equity (466,420) 146,270 951 - 313,372 (5,827)
---------- ---------- ------------ ----------- -------------- ----------
As at 31 December
2021 559 146,270 25,936 - (31,692) 141,073
========== ========== ============ =========== ============== ==========
CONSOLIDATED STATEMENT OF CASH FLOWS
for the year ended 31 December 2021
2021 2020
Notes USD'000 USD'000
------------------------------------------- -------- --------- ---------
Operating activities
Profit/(Loss) before tax 1,080 (57,238)
Adjustments for:
Depletion, depreciation and amortisation 7 69,024 68,414
Depreciation of right-of-use assets 7 11,191 16,228
Other finance costs 15 8,487 10,289
Assets written off 11 5,332 173
Allowance for slow moving inventories 11 2,624 143
11 /
Unrealised foreign exchange (gain)/loss 14 (1,838) 1,495
Share-based payments 8 951 1,128
(Reversal of)/Fair value loss
on oil derivatives 11 (471) 471
Change in fair value of contingent 15 /
payments 16 438 (359)
Accretion income on non-current
VAT receivables 16 (266) -
Interest expense 15 150 2,366
Interest income 14 (80) (257)
Impairment of intangible exploration
assets 13 - 50,455
Loss on ineffective hedge recycled
to profit or loss 11 - 4
Change in Stag FSO provision 14 - (5,047)
Gain from termination of right-of-use
asset 14 - (1,382)
Operating cash flows before movements
in working
capital 96,622 86,883
(Increase)/Decrease in trade and
other receivables (11,975) 35,560
Decrease/(Increase) in inventories 9,152 (14,071)
Increase in trade and other payables 21,631 3,736
Cash generated from operations 115,430 112,108
Interest paid (1,505) (1,542)
Tax refunded 3,652 -
Tax paid (15,486) (25,969)
--------- ---------
Net cash generated from operating
activities 102,091 84,597
--------- ---------
Investing activities
Cash received from acquisition
of Peninsular Malaysia
assets 19 29,252 -
Cash paid for acquisition of Peninsular
Malaysia
assets 19 (20,033) -
Net cash outflows on acquisition
of Lemang PSC 20 - (11,959)
Payment for oil and gas properties 22 (51,380) (4,732)
Payment for plant and equipment 23 (682) (473)
Payment for intangible exploration
assets 21 (3,858) (14,253)
Transfer from debt service reserve
account 29 8,445 5,040
Interest received 14 80 257
--------- ---------
Net cash used in investing activities (38,176) (26,120)
--------- ---------
2021 2020
Notes USD'000 USD'000
------------------------------------------- -------- --------- ---------
Financing activities
Proceeds from issuance of shares 30 967 406
(Placement)/Release of deposit
for bank guarantee 29 - 10,000
Dividend paid 31 (7,745) (2,493)
Repayment of borrowings 38 (7,296) (42,766)
Repayment of lease liabilities 38 (12,972) (18,562)
Net cash used in financing activities (27,046) (53,415)
--------- ---------
Net increase in cash and cash
equivalents 36,869 5,062
Cash and cash equivalents at beginning
of the year 80,996 75,934
--------- ---------
Cash and cash equivalents at end
of the year 29 117,865 80,996
========= =========
NOTES TO THE FINANCIAL STATEMENTS
for the year ended 31 December 2021
1. CORPORATE INFORMATION
Jadestone Energy plc (the "Company" or "Jadestone") is an oil
and gas company incorporated in the United Kingdom and registered
in England and Wales. The Company was incorporated on 22 January
2021, company registration number 13152520. The Company became the
ultimate parent company of the Group on completion of an internal
reorganisation (Note 2) on 23 April 2021. Prior to the internal
reorganisation, Jadestone Energy Inc., an oil and gas company
incorporated in Canada, had been the ultimate parent company of all
Jadestone subsidiaries (the "Group"). These consolidated financial
statements have been prepared for the Jadestone Energy Group and
reflect the full financial year ended 31 December 2021 in respect
of the ultimate parent company in accordance with IFRS (see Note
3).
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 and Indonesia.
The Group's producing assets are in the Vulcan (Montara) and
Carnarvon (Stag) basins, located in shallow water offshore of
Western Australia, and in the East Piatu, East Belumut, West
Belumut and Chermingat fields, located in shallow water in offshore
Peninsular Malaysia.
The Company's head office is located at 3 Anson Road, #13-01
Springleaf Tower, Singapore 079909. The registered office of the
Company is Suite 1, 3rd Floor, 11 - 12 St James's Square, London
SW1Y 4LB.
The financial information, comprising of the consolidated
statement of profit or loss and other comprehensive income,
consolidated statement of financial position, consolidated
statement of changes in equity, consolidated statement of cash
flows and related notes, has been taken from the consolidated
financial statements of Jadestone Energy plc ("Company") for the
year ended 31 December 2021, which were approved by the Board of
Directors on 3 June 2022. The financial information does not
constitute statutory accounts within the meaning of sections 435(1)
and (2) of the Companies Act 2006 or contain sufficient information
to comply with the disclosure requirements of International
Financial Reporting Standards ("IFRS").
An unqualified report on the consolidated financial statements
for the year ended 31 December 2021 has been given by the auditors,
Deloitte Ireland LLP. It did not include reference to any matters
to which the auditors drew attention by way of emphasis without
qualifying their report and did not contain any statement under
section 498 (2) or (3) of the Companies Act 2006. The consolidated
financial statements will be filed with the Registrar of Companies,
subject to their approval by the Company's shareholders at the
Company's Annual General Meeting on 30 June 2022.
2. SIGNIFICANT EVENTS DURING THE YEAR
Internal reorganisation
The Company completed an internal reorganisation on 23 April
2021, with Jadestone Energy plc becoming the ultimate holding
company of the Jadestone group of companies. The shares of
Jadestone Energy Inc., the former ultimate holding company, were
replaced on a one-for-one basis with shares of Jadestone Energy
plc. Following the completion of the internal reorganisation, the
shares of Jadestone Energy plc were admitted to AIM for trading on
26 April 2021 (shares of Jadestone Energy Inc. ceased trading on 23
April 2021).
The internal reorganisation did not result in a change in
control in the ultimate holding company nor the ultimate
shareholding or management of any Jadestone group company.
The reorganisation was undertaken for several reasons. It is
expected to reduce regulatory compliance burdens and raise the
Company's profile and status amongst UK and European investors who
are unable to invest in non-UK domiciled companies. It is also
expected to facilitate incremental access to equity from
international capital markets, and to allow Jadestone to further
optimise its tax structure.
Acquisition of SapuraOMV Peninsular Malaysia assets
On 30 April 2021, the Group executed a sale and purchase
agreement with SapuraOMV Upstream Sdn Bhd ("SapuraOMV") to acquire
SapuraOMV's Peninsular Malaysia assets (the "PenMal Assets"), for a
total cash consideration of US$20.0 million, which included a
headline price of US$9.0 million plus further working capital
adjustments of US$11.0 million. There are two separate potential
contingent payments which occur if the average Dated Brent is above
US$65/bbl in 2021 and above US$70/bbl in 2022. The Group paid the
first contingent payment of US$3.0 million in January 2022. The
acquisition completed on 1 August 2021, following the satisfaction
of all conditions precedent to closing the acquisition.
The economic effective date of the acquisition was 1 January
2021, meaning the Group is entitled to all net cash generated from
the PenMal Assets from 1 January 2021 to 31 July 2021, resulting in
a net cash receipt at closing of US$9.2 million.
The PenMal Assets comprise four licences, two of which are
operated by the Group, a 70% operated interest in the PM329 PSC,
containing the East Piatu field, and a 60% operated interest in the
PM323 PSC, which contains the East Belumut, West Belumut and
Chermingat fields. The other two licences comprise 50% non-operated
working interests in the PM318 and Abu, Abu Kecil, Bubu, North
Lukut, and Penara oilfields ("AAKBNLP") PSCs.
Oil price commodity contracts
On 16 February 2021, the Group entered into commodity swap
contracts to hedge 31% of its planned production volumes from April
to June 2021, to provide downside oil price protection in the
lead-up period to the Group's 2021 offshore Australia capital
programme. The average swap price, referenced to Dated Brent, was
set at US$61.40/bbl.
3. SUMMARY OF SIGNIFICANT 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.
Common control transaction
As disclosed in Note 2, the Company has completed an internal
reorganisation, with the shares of Jadestone Energy Inc. having
been replaced on a one-for-one basis with shares of Jadestone
Energy plc. Accordingly, the shares of Jadestone Energy plc were
admitted to AIM for trading on 26 April 2021. There is no change in
control in the ultimate holding company of the Group, nor the
ultimate shareholding or management of any Jadestone group company,
arising from the completion of the internal reorganisation.
IFRS 3 Business Combinations does not prescribe the presentation
and disclosure requirements under a common control transaction. The
Group has chosen to issue these consolidated financial statements
under the name of Jadestone Energy plc, as if they are a
continuation of the financial statements of Jadestone Energy Inc.
and Jadestone Energy plc had been in existence throughout the
reported financial year.
The following have been reflected in these consolidated
financial statements in relation to the common control
transaction:
a) The asset and liabilities of Jadestone Energy plc and
Jadestone Energy Inc. ("JEI") group have been recognised at their
book values immediately prior to the internal reorganisation;
b) The pre-internal reorganisation accumulated losses recognised
in these consolidated financial statements are those of JEI
Group;
c) The amount recognised as issued equity instruments in these
consolidated financial statements is the issued and paid-up share
capital of JEI immediately before the internal reorganisation. The
comparative share capital is that of the Company as if the Company
headed the Group for the comparative period;
d) The equity structure appearing in these consolidated
financial statements (i.e., the number and type of equity
instruments issued) reflects the equity structure of the
Company;
e) A merger reserve account was created to account the
difference between the carrying value and the nominal value of the
shares of the Company; and
f) The comparative information presented in these consolidated
financial statements is that of JEI Group with the exception of the
composition of the equity items which reflect that of the Company
as if the Company had existed for the comparative period.
GOING CONCERN
The Directors are required to consider the availability of
resources to meet the Group's liabilities for the foreseeable
future.
As at 31 December 2021, the Group has a total cash and cash
equivalents of US$117.9 million, and the Group managed to keep the
cash levels within the range of US$90.0 to US$105.0 million between
January to April 2022, after the settlements of trade related
expenditure and US$3.0 million contingent payment paid to SapuraOMV
arising from the acquisition of PenMal Assets (Notes 19 and 38).
The average Dated Brent crude prices for the first four months in
2022 was US$102.73/bbl, hence the Group was able to generate
material cash inflows from the liftings in Australia and Malaysia
from the beginning of 2022 up to date.
The Group regularly monitors its cash, funding and liquidity
position. Near term cash projections are revised and underlying
assumptions reviewed, generally monthly, and longer-term
projections are also updated regularly. Downside price and other
risking scenarios are considered, such as potential delay in the
development of Lemang asset, unfavourable foreign exchanges and
higher than expected inflation rates. In addition to commodity
sales prices, the Group is also potentially exposed to potential
production interruptions such as weather downtime and planned and
unplanned shutdowns for workovers and repair and maintenance
activities. All these factors have been considered in the Group's
near and longer term cash projections. For the purposes of the
Group's going concern assessment, we have reviewed cash projections
for the period from 1 April 2022 to 31 December 2023, the 'going
concern period'.
The Group is debt-free, following the final repayment of its
Australian reserve based lending facility in Q1 2021. All of its
operational and capital commitments (Note 43) can be funded from
the existing cash resources.
Having taken into consideration the above factors, the Directors
have reasonable expectation that the Group has adequate resources
to continue in operational existence for the going concern period.
Accordingly, they adopted the going concern basis in preparing
these 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 amendment
that is effective from the beginning of the year and is relevant to
its operations. The adoption of this amendment has not resulted in
changes to the Group's accounting policies.
Amendments to IFRS COVID-19-Related Rent Concessions Beyond
16 30 June 2021
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 Classification of Liabilities as Current
1 (1) or Non-current
Amendments to IAS Making Materiality Judgements - Disclosure
1 and Practice Statement of Accounting Policies
2(1)
Amendments to IAS Definition of Accounting Estimates
8(1)
Amendments to IAS Deferred Tax Related to Assets and Liabilities
12(1) Arising from a Single Transaction
Amendments to IAS Property, Plant and Equipment - Proceeds
16(1) before Intended Use
Amendments to IAS Onerous Contracts - Cost of Fulfilling
37(2) a Contract
Amendments to IFRS Reference to Conceptual Framework
3(2)
Amendments to IFRSs Annual Improvements to IFRS Standards
(2) 2018 - 2020
The Group is currently performing an assessment of the impact of
these amendments but does not expect a material impact on the
financial statements of the Group in future periods.
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
and to the non-controlling interests, even if this results in the
non-controlling interests having a deficit balance.
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.
(1) Effective from 1 January 2023.
(2) Effective from 1 January 2022.
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 PSCs 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.
PRE-LICENCE AWARD COSTS
Costs incurred prior to the effective award of oil and gas
licences, concessions and other exploration rights, are expensed in
profit or loss.
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 cess payment amount is assessed based on
the estimated future decommissioning expenditures. 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.
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.
GOVERNMENT GRANTS
Government grants are not recognised until there is reasonable
assurance that the Group will comply with the conditions attached
to them and that the grants will be received.
The government grants received in 2020 related to the Australian
Government's JobKeeper Scheme, as part of the Australian Government
initiative to provide immediate financial support as a result of
the COVID-19 pandemic, and applied to certain of the Group's
Australian offshore and onshore personnel. There are no future
related costs in respect of these grants, which were received
solely as compensation for costs incurred during the year. There
are no unfulfilled conditions or other contingencies in relation to
the grants.
Government grants are recognised in profit or loss on a
systematic basis over the periods in which the Group recognises as
expenses the related costs for which the grants are intended to
compensate.
Government grants are presented on a net basis in profit or
loss, where grant income is offset against the related costs, in
either "production costs" (Note 6) or " administrative staff costs"
(Note 8).
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 expected not 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 ASSETS EXCLUDING GOODWILL
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). Where there is common
infrastructure that is not possible to measure the cash flows
separately for each oil or gas field, then based on the aggregate
of the relevant oil or gas fields. 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.
Intangible assets with indefinite useful lives and intangible
assets not yet available for use, are tested for impairment
annually, and whenever there is an indication that the asset may be
impaired.
Recoverable amount is the higher of fair value less costs of
disposal ("FVLCOD") and value in use. In assessing value in use,
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. Assumptions relating
to forecast capital expenditures that enhance the productive
capacity can be included in the discounted cash flows model, but
only to the extent that a typical market participant would take a
consistent view. The post-tax discounted cash flows are compared
against the carrying amount of the asset on an after-tax basis;
that is, after deducting deferred tax liabilities relating to the
asset or group of assets.
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 11) 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 14) 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.
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 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 16) or "finance
costs" (Note 15) 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 fair value of the proceeds received.
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
Those hedges which hedge 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, are classified as cash flow hedges.
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 40 sets out details of the fair values of the derivative
instruments used for hedging purposes.
Movements in the hedging reserve in equity are detailed in Note
33.
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 16) or
"finance costs"
(Note 15) 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. In
2020, the Group had revalued certain lease liabilities to nil
following the termination of those leases.
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 35.
RETIREMENT BENEFIT OBLIGATIONS
Payments to defined contribution retirement benefit plans are
charged as an expense as and when employees have tendered the
services entitling them to the contributions. Payments made to
state managed retirement benefit schemes, such as Malaysia's
Employees Provident Fund, are dealt with as payments to defined
contribution plans where the Group's obligations under the plans
are equivalent to those arising in a defined contribution
retirement benefit plan. The Group does not have any defined
benefit plans.
REVENUE
Revenue from contracts with customers is recognised in 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.
An overlift liability is recorded as a current liability in the
statement of financial position at the prevailing market price, to
represent a provision for production costs attributable to the
volumes sold in excess of entitlement. An underlift asset is
recorded as a current receivable in the statement of financial
position at the prevailing market price, to represent a right to
additional inventory based on its entitlement. Movements during an
accounting period are adjusted through production costs such that
gross profit is recognised on an entitlement basis.
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 for the
year. Taxable profit differs from profit 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. In calculating the deferred tax in relation to PRRT, the
PRRT rate is combined with 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 in the current year is presented
as cash and cash equivalents in the consolidated statement of
financial position and disclosed in Note 29.
4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION
UNCERTAINTY
CLIMATE CHANGE AND ENERGY TRANSITION
The Group recognises that 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 asset retirement obligations provision. The
Group acknowledges that there are 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 of the forecasted long-term prices and demand for oil
and gas under the Paris aligned scenarios. See the key estimates on
page 42 for reserves estimates and impairment of oil and gas
properties.
While the pace of transition to a lower carbon economy is
uncertain, oil and gas demand is expected to remain a key element
of the energy mix in the foreseeable future based on stated
policies, commitments and announced pledges to reduce
emissions.
Therefore, given the useful lives of the Group's current
portfolio of oil and gas assets of up to 2040, management does not
expect the potential decline on oil prices as a result of climate
change and the transition to a lower carbon economy will have a
material adverse change to the operating cash flows of the Group
during the lives of those assets and thus the carrying amounts of
the Group's assets and liabilities will not be significantly
impacted.
Management will continue to review price assumptions as the
energy transition progresses and will take into consideration in
the future impairment assessments.
Critical accounting judgments
In the application of the Group's accounting policies,
management is required to make judgments, estimates and assumptions
about the carrying amounts of assets and liabilities that are not
readily apparent from other sources. The estimates and associated
assumptions are based on historical experience and other factors
that are considered to be relevant. Actual results may differ from
these estimates.
The estimates and underlying assumptions are reviewed on an
ongoing basis. Revisions to accounting estimates are recognised in
the period in which the estimate is revised, if the revision
affects only that period, or in the period of the revision and
future periods, if the revision affects both current and future
periods.
The following are the critical judgements, apart from those
involving estimates (see below) that management has 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.
-- 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. Accordingly, the Group considers if there is the
existence of business elements (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
both acquisition of PenMal Assets and Lemang PSC have been set out
in Notes 19 and Note 20, respectively.
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) Deferred taxes
The Group recognises the net future economic benefit of deferred
tax assets to the extent that it is probable that the deductible
temporary differences will reverse in the foreseeable future and
the carry forward of unutilised tax credits and unutilised tax
losses can be utilised accordingly. Assessing the recoverability of
deferred income tax, PRRT and PITA assets require the Group to make
significant estimates related to expectations of future taxable
income. Estimates of future taxable income are based on forecast
cash flows from operations and the application of existing tax laws
in each jurisdiction. To the extent that future cash flows and
taxable income differ significantly from estimates, the ability of
the Group to realise the net deferred tax assets as recorded in the
statement of financial position, could be impacted.
The carrying amount of the Group's deferred tax assets are
disclosed in Note 26 to the financial statements.
Sensitivity analysis
Sensitivities have been run on the oil price assumption, with a
10% change being considered a reasonable possible change for the
purposes of sensitivity analysis. A 10% decrease/increase in oil
price would not result in a change in the deferred tax asset
recognised by the Group due to the unrecognised deferred tax assets
being associated with the unwinding of provision of asset
retirement obligations in the future during the decommissioning
period. The Group is not expected to be in taxable profit position
during the decommissioning period to enable it to utilise the
unrecognised deferred tax assets at year end.
b) Reserves estimates
The Group's estimated reserves are management assessments, and
take into consideration audits performed by an independent third
party, which includes various assumptions, interpretations and
assessments. These include assumptions regarding commodity prices,
exchange rates, future production, transportation costs, 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, management does not expect a five percent
increase/decrease in the reserve estimates would significantly
impact the carrying amounts of the assets and liabilities of the
Group at year
end.
c) Impairment of oil and gas properties and intangible exploration assets
The Group undertakes a regular review of asset carrying amounts
to determine whether there is any indication of impairment. In the
impairment assessment 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.
For oil and gas properties, management assesses recoverable
amounts using the FVLCOD 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. Management further
takes into consideration the impact of climate change on estimated
future commodity prices with the application of the Paris aligned
price assumptions.
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.
Sensitivity analysis
Management assessed 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. The forecasted price assumptions are US$75/bbl in 2022,
US$70/bbl in 2023 and US$66/bbl from 2024 onwards. Based on the
analysis performed, management concluded that a price reduction in
isolation under the various scenarios would not impact the carrying
amount of the Group's oil and gas properties. Management also
assessed the impact of a change in cash flows in impairment testing
arising from the application of the various Paris aligned price
assumptions, being Announced Pledges Scenario (II), Net Zero
Emissions by 2050 Scenario (central) and Net Zero Emissions by 2050
Scenario (APD) as disclosed on pages 35 to 38 of Jadestone's 2021
annual report. The oil price under the various Paris aligned price
assumptions are as follow:
2027
2022 2023 2024 2025 2026 onwards
US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl US$/bbl
--------------------- ------- ------- ------- ------- ------- --------
Announced Pledges
Scenario
(II) 71.7 70.9 64.9 59.9 56.3 63.1
Net Zero Emissions
by 2050
Scenario (central) 67.8 65.3 57.5 50.7 46.5 42.9
Net Zero Emissions
by 2050
Scenario (APD) 71.3 70.4 64.2 58.9 54.5 51.7
Based on the analysis performed, the reduction in operating cash
flows under the various Paris aligned price assumptions would not
result in an impairment on the carrying amount of the Group's oil
and gas properties.
The oil price sensitivity analysis above does not, however,
represent management's 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.
Management also tested the impact of a five percent change in
the discount rate used of 10% for impairment testing of oil and gas
properties, and concluded that a one percent increase/decrease in
the discount rate will not result in impairment as the net present
value of either outcome is above the carrying amount of the Group's
oil and gas properties at year end.
d) 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 management
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 asset restoration
obligations is disclosed in Note 35 to the financial
statements.
Sensitivity analysis
Sensitivities have been run on the discount rate assumption,
with a one percentage change being considered a reasonable possible
change for the purposes of sensitivity analysis. A one percentage
reduction in discount rate would increase the liability by US$41.9
million and a one percentage increase in discount rate would
decrease the liability by US$36.4 million. A 10% increase in
current estimated costs would increase the liability by US$35.8
million and a 10% decrease in current estimated costs would
decrease the liability by US$35.3 million. A one year deferral to
the estimated decommissioning date would decrease the liability by
US$1.1 million and an acceleration of one year to the estimated
decommissioning date would increase the liability by US$0.2
million.
5. 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 3,
all revenue is recognised at a point in time.
2021 2020
USD'000 USD'000
----------------- --------- ---------
Liquids revenue 339,210 186,572
Hedging income - 31,366
--------- ---------
339,210 217,938
Gas revenue 984 -
--------- ---------
340,194 217,938
========= =========
The Group entered into Australian commodity swap contracts
hedging approximately 30% of its planned production for the period
January to June 2021. The commodity swap contracts were measured at
FVTPL as opposed to hedge accounting, in part because the swap
contracts cover a short time span. The swap contracts incurred a
loss of US$4.6 million during the year which is recorded as other
expense (Note 11).
The hedging income in 2020 arose from the Group's capped swap
contracts from October 2018 to September 2020 by hedging 50% of its
planned production volumes during the contracts' duration.
6. PRODUCTION COSTS
2021 2020
USD'000 USD'000
------------------------------------------- --------- ---------
Operating costs 61,630 45,155
Workovers 67,006 21,686
Logistics 20,212 18,853
Repairs and maintenance 45,186 22,450
Tariffs and transportation costs 2,809 -
Underlift, overlift and crude inventories
movement 9,680 (2,806)
--------- ---------
206,523 105,338
========= =========
Operating costs predominately consists of offshore manpower
costs of US$26.8 million (2020: US$20.7 million), chemical,
services, supplies and others of US$20.3 million (2020: US$20.3
million), Malaysian supplementary payments of US$8.3 million (2020:
nil), insurance of US$2.7 million (2020: US$3.0 million) and
non-operated assets production costs of US$1.2 million (2020: nil).
The Malaysian supplementary payments are required under the terms
of PSCs based on the Group's entitlement to profit from oil and
gas. It is payable at 70% of the excess revenue over the base price
of the sale of oil as set out under the terms of PSCs. The payments
are made to PETRONAS.
Workovers in 2021 included the Montara subsea workovers for the
Skua 10 and Skua 11 wells of US$47.2 million, net of insurance
claim receivable of US$10.3 million on the well control claim for
the Skua 11 well workovers.
Repairs and maintenance in 2021 include a
once-in-every-three-year subsea flowline inspection and Swift North
subsea control module change out at Montara and a once-in-five-year
changeout of the under-buoy hose at Stag.
The operating costs in 2020 were net of US$0.6 million received
during the year from the Australian Government's JobKeeper scheme
in respect of COVID-19 grants supporting certain of the Group's
Australian offshore workforce.
7. DEPLETION, DEPRECIATION AND AMORTISATION ("DD&A")
2021 2020
USD'000 USD'000
--------------------------------------- -------- --------
Depletion and amortisation (Note 22): 62,586 68,005
Depreciation of:
Plant and equipment (Note 23) 508 601
Right-of-use assets (Note 24) 11,191 16,228
Crude inventories movement 5,930 (192)
-------- --------
80,215 84,642
======== ========
The depreciation of right-of-use assets in 2021 includes US$1.5
million (2020: nil) associated with the Skua 10 and 11
workovers.
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.
Crude inventories movement represents the year on year
differential of the Group's on hand closing inventory. 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. There were 274,103 bbls at the end
of 2021 compared to 601,999 bbls at the end of 2020 reflecting an
additional depletion charge of US$5.9 million.
8. ADMINISTRATIVE STAFF COSTS
2021 2020
USD'000 USD'000
-------------------------- -------- --------
Wages, salaries and fees 21,066 17,520
Staff benefits in kind 3,051 3,255
Share-based compensation 951 1,128
-------- --------
25,068 21,903
======== ========
The compensation of key management personnel is included in the
above and disclosed separately in Note 46.
Wages, salaries and fees in 2020 were net of US$0.5 million
received during the year from the Australian Government's JobKeeper
scheme in respect of certain of the Group's Australian onshore
personnel.
9. STAFF NUMBERS AND COSTS
The average number of employees employed by the Group during the
year was 278 (2020: 210), consisting of 153 onshore employees
(2020: 117) and 125 offshore employees (2020: 93). Staff costs are
split between production costs (Note 6) for offshore personnel and
administrative staff costs (Note 8) for onshore personnel.
Their aggregate remuneration comprised:
2021 2020
USD'000 USD'000
------------------------------------ -------- --------
Wages and salaries 39,158 35,434
Social security costs 186 206
Defined contribution pension costs 3,177 2,594
Share-based compensation 951 1,128
-------- --------
43,472 39,362
Contractors and consultants costs 8,363 3,191
-------- --------
51,835 42,553
======== ========
10. DIRECTORS' REMUNERATION AND TRANSACTIONS
2021 2020
USD'000 USD'000
---------------------------------------------- -------- --------
Directors' remuneration
Salaries, fees, bonuses and benefits in
kind 3,093 2,823
Gains on exercise of options 1,259 -
Amounts receivable under long term incentive
plans 278 493
Money purchase pension contributions 96 72
-------- --------
4,726 3,388
======== ========
Remuneration of the highest paid Director:
Salaries, fees, bonuses and benefits in
kind 1,516 1,472
Gains on exercise of options 481 -
Amounts receivable under long term incentive
plans 302 282
Money purchase pension contributions 63 44
-------- --------
2,362 1,798
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 2 -
Had awards receivable in the form of shares
under a long-term
incentive scheme 2 8
======== ========
In 2021, the Non-Executive Directors were not granted any
options/shares under the Company's long term incentive plans,
compared to 2020 when all Directors were granted share options.
11. OTHER EXPENSES
2021 2020
USD'000 USD'000
--------------------------------------- -------- --------
Corporate costs 11,487 16,642
Assets written off 5,332 173
Loss on valuation of oil derivatives 4,633 475
Provision for slow moving inventories 2,624 143
Net foreign exchange loss 950 2,623
Rig contract deferral costs - 3,000
Exploration expenses - 972
Other expenses 1,155 2,890
-------- --------
26,181 26,918
======== ========
Corporate costs in 2021 includes business development costs of
US$3.2 million, professional fees in relation to internal
reorganisation of US$1.1 million and project transition costs of
US$0.9 million (2020: US$1.0 million). Corporate costs in 2020
included US$9.1 million of litigation costs incurred in relation to
the SC56 and Block 05-1 PSC.
Loss on valuation of oil derivatives arose from the Australian
commodity swap contracts entered for the period January to June
2021.
Assets written off in 2021 includes the written off of
intangible exploration assets of US$5.3 million previously
capitalised as they are not expected to generate future economic
benefits.
For the purpose of the consolidated statement of cash flows, net
foreign exchange loss in 2020 included net unrealised loss of
US$1.5 million.
Rig contract deferral costs in 2020 of US$3.0 million arose from
the decision to defer the Australian 2020 drilling campaign in
response to the impact of COVID-19.
12. AUDITORS' REMUNERATION
The analysis of the auditor's remuneration is as follows:
2021 2020
USD'000 USD'000
--------------------------------------------- -------- --------
Fees payable to the Company's auditor for
the audit of the parent
company and Group's consolidated financial
statements 383 208
Audit fees of the subsidiaries 412 174
-------- --------
795 382
======== ========
No fees were paid to the Group's auditors for non-audit services
for either the Group or the Company in 2020 or 2021.
The increase in fees relates mainly to the internal
reorganisation in April 2021 which required the Group auditors to
be United Kingdom rather than Singapore based.
13. IMPAIRMENT OF ASSETS
2021 2020
USD'000 USD'000
--------------------------------------------- --------- --------
Impairment of intangible exploration assets
(Note 21) - 50,455
========== ========
The impairment expense of US$50.5 million in 2020 related to
management's decision to voluntarily relinquish SC56, a deepwater
new basin entry exploration block acquired by the previous
management of the Group. The effective date of relinquishment was
21 December 2020. During the year, the Group paid an exit fee of
US$1.5 million to the Philippines Department of Energy and formally
exited the block. A provision was made in relation to the exit fee
in 2020 which reversed out in 2021 after the payment was made.
14. OTHER INCOME
2021 2020
USD'000 USD'000
------------------------------------------------- -------- --------
Net foreign exchange gain 2,525 48
Interest income 80 257
Litigation income - 11,075
Reversal of Stag FSO provision - 5,047
Fair value gain on foreign exchange derivatives - 3,784
Gain from termination of right-of-use asset - 1,382
Other income 5,077 4,783
-------- --------
7,682 26,376
======== ========
Other income includes rental income from a helicopter rental
contract (a right-of-use asset) to a third party of US$4.5 million
(2020: US$3.6 million). Other income in 2020 also consisted of a
settlement sum of US$1.0 million received from Teikoku Oil (Con
Son) Co. Ltd, a subsidiary of Inpex Corporation, to resolve the
dispute between both parties over the Block 05-1 PSC.
For the purpose of the consolidated statement of cash flows, net
foreign exchange gain in current year includes net unrealised gain
of US$1.8 million.
Litigation income in 2020 represented the arbitration award
granted by Singapore International Arbitration Centre in favour to
the Group in response to a breach of the SC56 farm out agreement by
Total E&P Philippines BV.
15. FINANCE COSTS
2021 2020
USD'000 USD'000
------------------------------------------ -------- --------
Interest expense 150 2,366
Accretion expense for asset retirement
obligations (Note 35) 5,920 6,312
Interest expense on lease liabilities 1,222 3,341
Changes in provisions:
Lemang PSC contingent payments 314 -
PenMal Assets contingent payment 124 -
Accretion expense for Stag FSO provision - 51
Other finance costs 1,345 585
-------- --------
9,075 12,655
======== ========
Interest expense refers to the effective interest charge on the
reserve based lending facility.
The fair value of the contingent payments payable to Mandala
Energy Lemang Pte Ltd for the Lemang PSC acquisition were revalued
to US$4.8 million as at 31 December 2021 (2020: US$4.4 million),
reflecting the effect of the time value of money for the trigger
events as disclosed in Note 20.
The consideration for the PenMal Assets included two separate
contingent payments for US$3.0 million each if the average Dated
Brent remained equal or above US$65/bbl in 2021 and US$70/bbl in
2022. The contingent payments had a fair value of US$4.3 million
(see Note 19.3) on the date of acquisition. At year end, the
contingent payments were revalued at US$4.4 million, resulting in
an increase in the provision of US$0.1 million.
Other finance costs include accretion expense of US$1.2 million
(2020: US$0.5 million) generated from an Australian Taxation Office
("ATO") 2019 repayment plan of US$43.3 million to support companies
impacted by COVID-19. The repayment schedule was between December
2020 and June 2022 but the plan was fully repaid in May 2022.
16. OTHER FINANCIAL GAINS
2021 2020
USD'000 USD'000
------------------------------------------ -------- --------
Change in provision:
Montara contingent payments - 359
Accretion income from non-current Lemang 266 -
PSC VAT receivables
-------- --------
266 359
======== ========
The accretion income represents the effect of the time value of
money on the non-current Lemang PSC VAT receivables. The fair value
of the VAT receivables were revalued to US$4.7 million as at 31
December 2021 (2020: US$4.4 million).
The change in provision represents the change in the fair value
of the Montara contingent payments. The Group derecognised the
Montara 2020 contingent payment in 2020 as the trigger event to
crystallise this payment did not arise. The fair values of the
remaining Montara contingent payments have been valued at US$ nil,
as the possibility of realisation is remote.
17. INCOME TAX EXPENSE
2021 2020
USD'000 USD'000
------------------------------------------- --------- ---------
Current tax
Corporate tax (credit)/charge (486) 11,020
Overprovision in prior year (270) (1,030)
--------- ---------
(756) 9,990
Australian petroleum resource rent tax
("PRRT") (1,374) 1,678
Malaysian petroleum income tax ("PITA") 9,469 -
7,339 11,668
--------- ---------
2021 2020
USD'000 USD'000
------------------------------------------- --------- ---------
Deferred tax
Corporate tax 5,247 (4,026)
PRRT 3,371 (4,702)
PITA (1,135) -
========= =========
7,483 (8,728)
--------- ---------
14,822 2,940
========= =========
Jadestone Energy Inc., the former ultimate holding company, was
a resident in the Province of British Columbia and paid no Canadian
tax. The Group has no operating business in Canada. Following the
completion of the internal organisation (Note 2), Jadestone Energy
plc became the ultimate holding company on 23 April 2021. 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.
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.
During the year, Stag recorded a net PRRT expense of US$2.0
million (2020: PRRT credit of US$3.0 million), after utilising PRRT
carried forward credits of US$4.7 million from 2020.
As at year end, Montara has US$3.4 billion (2020: US$3.3
billion) of unutilised PRRT carried forward credits. Based on
management's latest forecasts, the augmentation on historic
accumulated PRRT net losses will more than offset PRRT that would
otherwise arise on future PRRT taxable profits. Accordingly,
Montara is not anticipated to incur any PRRT expense.
PenMal Assets recorded PITA expense of US$8.3 million since the
completion of acquisition on 1 August 2021.
The tax recoverable of US$9.4 million as at year end represents
PITA receivable of which US$5.1 million arose from pre-economic
effective date of the PenMal Assets acquisition which will be
payable to SapuraOMV following the receipt from tax refund. The
Group has recognised the payable to SapuraOMV as at year end.
The tax expense on the Group's profit/(loss) differs from the
amount that would arise using the standard rate of income tax
applicable in the countries of operation as explained below:
2021 2020
USD'000 USD'000
-------------------------------------------------- --------- -----------
Profit/(Loss) before tax 1,080 (57,238)
========= ===========
Tax calculated at the domestic tax rates
applicable to the profit/loss in the respective
countries (Australia 30% & 40%, Malaysia
24% & 38%, New Zealand 28%, Canada 27%
and Singapore 17%) 3,948 (9,198)
Effects of non-deductible expenses 3,803 16,192
Effect of PRRT/PITA tax expense 8,095 1,678
Deferred PRRT/PITA tax expense/(credit) 2,238 (4,702)
Effect of unutilised tax losses recognised
as deferred tax asset (2,992) -
Overprovision in prior year (270) (1,030)
--------- -----------
Tax expense for the year 14,822 2,940
========= ===========
In addition to the amount charged to the profit or loss, the
following amounts relating to tax have been recognised in other
comprehensive income.
2021 2020
USD'000 USD'000
----------------------------------------- --------- ---------
Other comprehensive loss - deferred tax
Income tax credit related to carrying
amount of hedged item - (1,583)
========== =========
18. LOSS PER ORDINARY SHARE
The calculation of the basic and diluted loss per share is based
on the following data:
2021 2020
USD'000 USD'000
------------------------------------------------ ------------- -------------
Loss for the purposes of basic and diluted
per share, being the net loss for the year
attributable to equity holders of the Company (13,742) (60,178)
============= =============
2021 2020
Number Number
------------------------------------------------ ------------- -------------
Weighted average number of ordinary shares
for the purposes of
basic EPS 463,567,519 461,309,862
Effect of diluted potential ordinary shares
- share options - -
------------- -------------
Weighted average number of ordinary shares
for the purposes of
dilutive EPS 463,567,519 461,309,862
============= =============
In 2021, 6,640,985 (2020: 4,679,402) 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 2021, 899,306 (2020: 651,687) 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 2021, 140,965 (2020: 68,480) 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.
Loss per share (US$) 2021 2020
-------------------------- -------- --------
* Basic and diluted (0.03) (0.13)
======== ========
19. ACQUISITION OF SAPURAOMV (PM) INC.
19.1 Effective Date and Acquisition Date
On 30 April 2021, the Group executed a sale and purchase
agreement ("SPA") with SapuraOMV Upstream (PM) Sdn Bhd
("SapuraOMV") to acquire the entire share capital of SapuraOMV (PM)
Inc. for a cash consideration of US$20.0 million, comprising a
headline price of US$9.0 million, plus customary adjustments of
US$11.0 million (see Note 19.3). There are two separate potential
contingent payments to SapuraOMV of US$3.0 million each related to
the annual average Dated Brent price equal or above US$65/bbl in
2021 and US$70/bbl in 2022.
The acquisition completed on 1 August 2021, following the
satisfaction of all conditions precedent. The economic effective
date of the acquisition, as set out in the SPA, was 1 January 2021,
meaning the Group was entitled to all net cash generated since 1
January 2021 up to the completion date. As a result, at completion
on 1 August 2021, the Group obtained cash held by SapuraOMV (PM)
Inc. of US$29.2 million, resulting in net cash receipts of US$9.2
million.
The legal transfer of ownership and control of SapuraOMV (PM)
Inc. occurred on the date of completion, 1 August 2021 (the
Acquisition Date). It was at this point that the Group became able
to control the key operating decisions relating to the acquired
entity. Therefore, for the purpose of calculating the purchase
price allocation, management has determined the fair value
adjustments using the balance sheet of the SapuraOMV (PM) Inc. as
at the completion date of 1 August 2021.
On 3 August 2021, the name of SapuraOMV (PM) Inc. was changed to
Jadestone Energy (PM) Inc. ("JEPM").
19.2 Business acquisition
Management has concluded that the acquisition of JEPM is that of
a business as defined in IFRS 3 Business Combinations. JEPM
contains inputs and processes, which when combined has the ability
to contribute to the creation of outputs (oil and gas).
Accordingly, the transaction has been accounted for as a business
combination.
As a result, the Group has applied the acquisition method of
accounting as at the Acquisition Date. A purchase price allocation
exercise was performed to identity, 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.
19.3 Fair value of consideration transferred
The fair value consideration for the PenMal Assets reflected a
net cash receipt of US$9.2 million, as set out below:
USD'000
------------------------------------------------- ----------
Asset purchase price 9,000
Crude inventory value 3,236
Cash at bank, 1 January 2021 8,091
Closing statement adjustments (294)
----------
Cash payment on Acquisition Date 20,033
Less: cash and bank balances acquired, 1 August
2021 (29,252)
----------
Net cash receipts from the acquisition (9,219)
==========
The crude inventory was measured at the market value and the
cash at bank represents the cash on hand, as at the economic
effective date of 1 January 2021.
The closing statement adjustments relates to permitted leakages
of US$0.3 million of audited intercompany charges that relate to
SapuraOMV Group (pre 1 January 2021).
In addition, there were two deferred potential contingent
payments of US$3.0 million each, payable depending on the outcome
of two trigger events, namely that the average Dated Brent oil
price would equal or exceed US$65/bbl in 2021 and US$70/bbl in
2022. If either or both events occur, the respective contingent
payment would be paid within 30 days from the end of each calendar
year.
Management has assessed the fair value of the deferred
contingent payments using a Monte Carlo option simulation model,
which considered inputs such as spot Brent oil price at completion
date, the risk-free rate, a volatility factor and the length of
time the contingent payments apply. The fair value of both
contingent payments was assessed to be US$4.3 million, representing
US$3.0 million and US$1.3 million for the 2021 and 2022 deferred
contingent payments, respectively. The 2022 contingent payment
reflects a discount of 57% from the original value, reflecting the
time value of money and the likelihood of the trigger event
occurring. The assessment of 2022 contingent payment was performed
as at 1 August 2021, based on the facts and circumstances existed
as at that date. Subsequent to year end, the oil prices have seen
an abnormal increase, accordingly the Group is likely to pay the
2022 contingent payment in full.
The 2021 contingent payment of US$3.0 million crystalised at
year end as the average Dated Brent oil price exceeded US$65/bbl,
hence the amount was recognised as an accrual at year end. The
amount was paid in January 2022.
Fair value of purchase consideration USD'000
-------------------------------------- ---------
Asset purchase price 9,000
Crude inventory value 3,236
Cash at bank 8,091
Closing statement adjustments (294)
---------
Cash payment on Acquisition Date 20,033
Working capital adjustment (1,059)
Deferred contingent consideration 4,305
---------
Fair value of purchase consideration 23,279
=========
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
SapuraOMV during the sales process period and there were a number
of other interested parties in the formal sale process;
-- Knowledgeable, willing but not anxious parties: both the
Group and SapuraOMV 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
SapuraOMV. 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 the stipulated time period of 12 months from the
Acquisition Date, in accordance with IFRS 3. The adjusted fair
values of the identifiable assets and liabilities as at the
Acquisition Date were:
USD'000
-------------------------------------------------- ---------
Asset
Non-current assets
Oil and gas properties (Note 22) 21,744
Other receivables 42,092*
Deferred tax assets 10,343
Current assets
Inventories 2,853
Trade and other receivables 21,276
Tax recoverable 10,226
Cash and bank balances 29,252
---------
137,786
---------
USD'000
-------------------------------------------------- ---------
Liabilities
Non-current liabilities
Provision for asset retirement obligations (Note
35) 91,552
Deferred tax liabilities 6,177
Current liabilities
Trade and other payables 16,778
114,507
---------
Net identifiable assets acquired 23,279
=========
* Other receivables represent the accumulated CESS paid to the
Malaysian regulator for operated licences, which will be
reclaimable by the Group in the future following the commencement
of decommissioning activities.
19.5 Impact of acquisition on the results of the Group
Included in the Group's revenue for the year was US$46.6 million
attributable to the PenMal Assets. Included in the Group's after
tax loss for the year was a profit of US$6.5 million attributable
to the PenMal Assets.
Acquisition-related costs amounting to US$0.7 million have been
excluded from the consideration transferred and have been
recognised as an expense in the period, 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 2021,
and based on the performance of the business during 2021 under
SapuraOMV's operatorship, the Group would have generated revenues
of US$107.2 million and an estimated net profit after tax of
US$29.6 million.
The Directors of the Group consider these "pro-forma" numbers to
represent an approximate measure of the performance of the combined
Group on an annualised basis and to provide a reference point for
comparison in future periods.
20. ACQUISITION OF LEMANG PSC
20.1 Acquisition date
In 2020, the Group executed an acquisition agreement with
Mandala Energy Lemang Pte Ltd ("Mandala Energy") to acquire an
operated 90% interest in the Lemang PSC, for a total cash
consideration of US$12.0 million, including closing statement
adjustments and subsequent contingent payments. The acquisition
closed on 11 December 2020 ("Closing Date"), following the
completion of various conditions precedent at the time of signing
the acquisition agreement.
20.2 Asset acquisition
Management has concluded that the acquisition of the Lemang PSC
is an asset acquisition as the Lemang PSC does not come with an
organised workforce, and 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. Therefore,
the assets acquired and liabilities assumed in the acquisition of
the Lemang PSC, and the consideration transferred have been
measured at fair value, in accordance to the definition of fair
value under IFRS 13 Fair Value Measurement.
20.3 Fair value of consideration transferred
The fair value consideration of the Lemang PSC reflected net
cash outflows of US$12.0 million, as set out below:
USD'000
--------------------------------------- --------
Asset purchase price 12,000
Closing statement adjustments 55
--------
Cash payment on acquisition date 12,055
Less: cash and bank balances acquired (96)
--------
Net cash outflows on acquisition 11,959
========
The total net cash outflows on acquisition reflects the net
receipts arising from the working capital adjustments at the
Closing Date.
There are additional potential deferred contingent payments,
dependent on the future outcome of a number of trigger events.
Please refer to Note 20.5 for the full disclosure of all the
contingent payments along with the management's assessment.
Management has reviewed all the contingent payments, and at the
date of acquisition recorded an amount of US$4.4 million at fair
value for the following two contingent events:
- First gas date : US$5.0 million; and
- The accumulated receipts of VAT reimbursements received which
are attributable to 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.
Management has assessed the fair value of the above contingent
consideration based on the estimated timing of first gas date, and
the estimated receipts from the VAT receivables. This implies the
fair value of the contingent considerations to be US$3.9 million
and US$0.5 million, respectively, totalling US$4.4 million as at
Closing Date. This reflects a discount of 23% and 20% for the
respective contingent consideration payments arising from the time
value of money and the likelihood of the trigger event occurring.
There is no change to the fair value as at 2020 year end due to the
short timeframe from the Closing Date up to 2020 year end. As at 31
December 2021, the fair value of the contingent payments are valued
at US$4.8 million, reflecting the time value of money. The
contingent payments are not expected to be paid before 2024 and
accordingly have been classified as non-current liability.
The Group has not recognised other contingent payments
associated with the acquisition of the Lemang PSC as management
considers the probability of outflow to be remote.
Fair value of purchase consideration USD'000
-------------------------------------- --------
Asset purchase price 12,000
Closing statement adjustment 55
--------
Cash payment on acquisition date 12,055
Deferred contingent consideration 4,436
--------
Total 16,491
========
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
Mandala Energy during the sales process period and there a number
of other interested parties in the formal sale process;
-- Knowledgeable, willing but not anxious parties: both the
Group and Mandala Energy are experienced oil and gas operators
under no duress. 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
Mandala Energy. Both parties had engaged their own professional
advisors so there is no reason to conclude that the transaction was
not transacted at arm's length.
20.4 Assets acquired and liabilities assumed at the date of
acquisition
The fair value of the identifiable assets and liabilities of the
Lemang PSC, acquired and assumed as at the date of acquisition,
were:
USD'000
-------------------------------------------------- --------
Asset
Non-current assets
Intangible exploration assets (Note 21) 14,825
VAT receivables 4,393
Current assets
Trade and other receivables 398
Inventories 3
Cash and bank balances 96
--------
19,715
--------
Total
USD'000
-------------------------------------------------- --------
Liabilities
Non-current liabilities
Provision for asset retirement obligations (Note
35) 2,741
Current liabilities
Trade and other payables 483
--------
3,224
--------
Net identifiable assets acquired 16,491
========
The provision for asset restoration obligations assumed by the
Group is associated with oil production by Mandala Energy that
ceased prior to the acquisition in December 2020. The obligation
was assumed following the acquisition, and the decommissioning
expenditure is expected to be incurred from 2034, at the end of the
life of the planned gas development.
20.5 Deferred contingent consideration
No. Trigger event Consideration Management's rationale
--- ------------------------------ ---------------- -----------------------------------
1. First gas date US$5.0 million Please refer to 20.3 above.
2. The accumulated VAT US$0.7 million Please refer to 20.3 above.
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
3. First gas date on US$3.0 million It is unlikely that the
or before 31 March first gas date will be on
2023 or before 31 March 2023.
4. Total actual Akatara US$3.0 million The Akatara Gas Project
Gas Project "close has not been sanctioned
out" costs set out as at year end due to ongoing
in the AFE(s) approved preparation of project approval
pursuant to a joint documentation. It is unknown
audit by SKK MIGAS if the future close out
and BPKP is less costs will be less than
than, or within 2% or within 2% of the budgeted
of the "close out" amount and it is unable
development costs to be reliably measured
set out in the approved as at year end.
revised plan of development
for the Akatara Gas
Project
No. Trigger event Consideration Management's rationale
--- ------------------------------ ---------------- -----------------------------------
5. The average Saudi US$3.0 million Saudi CP is not expected
CP in the first year to be above US$620/MT throughout
of operation is higher the PSC term to 2037.
than US$620/MT
6. The average Saudi US$2.0 million Saudi CP is not expected
CP in the second to be above US$620/MT throughout
year of operation the PSC term to 2037.
is higher than US$620/MT
7. The average Dated US$2.5 million The Dated Brent price is
Brent price in the not expected to be above
first year of operation US$80/bbl throughout the
is higher than US$80/bbl PSC term to 2037.
8. The average Dated US$1.5 million The Dated Brent price is
Brent price in the not expected to be above
second year of operation US$80/bbl throughout the
is higher than US$80/bbl PSC term to 2037.
9. A plan of development US$3.0 million There are no prospects or
for the development leads presently selected
of a new discovery for the exploration well
made, as a result commitment. As at year end,
of the remaining it is not probable that
exploration well this contingent consideration
commitment under trigger will be met.
the PSC, is approved
by the relevant government
entity.
10. The plan of development US$8.0 million There are no prospects or
described in item leads presently selected
9 above is approved for the exploration well
by the relevant government commitment. As at year end,
entity and is based it is not probable that
on reserves of no this contingent consideration
less than 8.4mm barrels trigger will be met.
(on a gross basis).
21. INTANGIBLE EXPLORATION ASSETS
USD'000
-------------------------------------------------- -------------
Cost
As at 1 January 2020 117,440
Acquisition of Lemang PSC (Note 20) 14,825
Additions 18,860
-------------
As at 31 December 2020 151,125
Additions 3,934(a)
Change in asset retirement obligations (Note 35) (44)(b)
Reversal (6,059)(c)
Written off (55,715)(d)
-------------
As at 31 December 2021 93,241
=============
Impairment
As at 1 January 2020 -
Additions (Note 13) 50,455
-------------
As at 31 December 2020 50,455
Written off (50,455)
As at 31 December 2021 -
=============
Net book value
As at 1 January 2020 117,440
=============
As at 31 December 2020 100,670
As at 31 December 2021 93,241
=============
(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 2021 (2020: US$4.6
million).
(b) The change in asset retirement obligations of US$0.04
million relates to assets at the Lemang PSC.
(c) The US$6.0 million reversal during the year relates to an
overprovision of costs owed to a third party contractor. The
overprovision was identified following an assessment of actual
costs incurred.
(d) In November 2020, Total, as operator of SC56 voluntarily
surrendered a combined 100% interest in SC56 to the Philippines
Department of Energy ("DOE"). As a result, the carrying value of
US$50.4 million was impaired in Q4 2020. The DOE acknowledged the
relinquishment in February 2021 and the exit obligation terms were
agreed in June 2021. Accordingly, the carrying value was formally
written off in 2021.
The Group has also written off intangible exploration assets of
US$5.3 million during the year (Note 11).
22. OIL AND GAS PROPERTIES
USD'000
---------------------------------------------------- ---------
Cost
As at 1 January 2020 492,985
Changes in asset restoration obligations (Note 35) (725)
Additions 4,732
---------
As at 31 December 2020 496,992
Changes in asset restoration obligations (Note 35) 23,894
Acquisition of PenMal Assets (Note 19) 21,744
Additions 52,864*
As at 31 December 2021 595,494
=========
Accumulated depletion and amortisation
As at 1 January 2020 111,311
Charge for the year 68,005
As at 31 December 2020 179,316
Charge for the year 62,586
As at 31 December 2021 241,902
=========
Net book value
As at 1 January 2020 381,674
=========
As at 31 December 2020 317,676
As at 31 December 2021 353,592
=========
* The additions consist of cash payments of US$51.4 million and
capitalisation of depreciation of US$1.5 million associated with
right-of-use assets in Australia in accordance with IAS 16, both
associated with the drilling of the H6 infill well at Montara.
23. PLANT AND EQUIPMENT
Computer equipment Fixtures and fittings Materials and spares Total
USD'000 USD'000 USD'000 USD'000
------------------------- ------------------ ---------------------- --------------------- ---------
Cost
As at 1 January 2020 2,824 1,315 - 4,139
Additions 280 193 - 473
------------------ ---------------------- --------------------- ---------
As at 31 December 2020 3,104 1,508 - 4,612
Additions 450 232 - 682
Written off - (169) - (169)
Transfer - - 7,209 7,209*
---------------------
As at 31 December 2021 3,554 1,571 7,209 12,334
================== ====================== ===================== =========
Accumulated depreciation
As at 1 January 2020 1,334 1,025 - 2,359
Charge for the year 323 278 - 601
------------------ ---------------------- --------------------- ---------
As at 31 December 2020 1,657 1,303 - 2,960
Charge for the year 302 206 - 508
Written off - (97) - (97)
---------------------
As at 31 December 2021 1,959 1,412 - 3,371
================== ====================== ===================== =========
Net book value
As at 1 January 2020 1,490 290 - 1,780
================== ====================== ===================== =========
As at 31 December 2020 1,447 205 - 1,652
================== ====================== ===================== =========
As at 31 December 2021 1,595 159 7,209 8,963
================== ====================== ===================== =========
* 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$1.9 million as disclosed in Note 11.
24. RIGHT-OF-USE ASSETS
Production assets Transportation and logistics Buildings Total
USD'000 USD'000 USD'000 USD'000
Cost
As at 1 January 2020 29,339 42,320 3,004 74,663
Additions - 419 472 891
Termination (29,339) - (307) (29,646)
Adjustment - (394) - (394)
----------------- ----------------------------- ---------- ---------
As at 31 December 2020 - 42,345 3,169 45,514
Additions - 1,200 1,654 2,854
----------------- ----------------------------- ---------- ---------
As at 31 December 2021 - 43,545 4,823 48,368
================= ============================= ========== =========
Accumulated depreciation
As at 1 January 2020 5,334 8,519 1,023 14,876
Charge for the year 3,837 11,419 972 16,228
Termination (9,171) - (92) (9,263)
----------------- ----------------------------- ---------- ---------
As at 31 December 2020 - 19,938 1,903 21,841
Charge for the year - 11,470* 1,205 12,675*
----------------- ----------------------------- ---------- ---------
As at 31 December 2021 - 31,408 3,108 34,516
================= ============================= ========== =========
Net book value
As at 1 January 2020 24,005 33,801 1,981 59,787
================= ============================= ========== =========
As at 31 December 2020 - 22,407 1,266 23,673
================= ============================= ========== =========
As at 31 December 2021 - 12,137 1,707 13,852
================= ============================= ========== =========
* The amount includes US$1.5 million which has been capitalised
within oil and gas properties as the related right-of-use assets
were used as part of the drilling of the H6 infill well at Montara
(see Note 22).
The Group leases several assets including helicopters, a supply
boat, logistic facilities for the Montara field, and buildings. The
average lease term is 3 years.
The maturity analysis of lease liabilities is presented in Note
36.
2021 2020
USD'000 USD'000
--------------------------------------------- -------- --------
Amount recognised in profit or loss
Depreciation expense on right-of-use assets 11,191 16,228
Interest expense on lease liabilities 1,222 3,341
Expenses relating to short-term leases 63,734 3,113
Expense relating to leases of low value
assets 81 31
======== ========
At 31 December 2021, the Group has not committed to any
short-term leases (2020: US$8.1 million).
The total cash outflow for leases amount to US$13.0 million
(2020: US$18.6 million).
The additions of right-of-use assets during the year represent
the extension of the Group's ongoing right-of-use assets and
entered into a five-year lease to rent an Australian office
building to replace an expired lease.
25. INTERESTS IN OPERATIONS
Details of the operations, of which all are in production except
for 46/07, 51 and Lemang which are in the development stage, are as
follows:
Group effective working interest % as at 31
Place of December
Contract Area Date of expiry Held by operations 2021 2020
------------- -------------- ----------------------- ----------- ----------------------- ------------------------
Montara Jadestone Energy
oilfield Indefinite (Eagle) Pty Ltd Australia 100 100
Jadestone Energy
Stag Oilfield 25 Aug 2039 (Australia) Pty Ltd Australia 100 100
PM329 8 December Jadestone Energy (PM) Malaysia 70 -
2031 Inc.
PM323 14 June 2028 Jadestone Energy (PM) Malaysia 60 -
Inc.
PM318 24 May 2034 Jadestone Energy (PM) Malaysia 50 -
Inc.
AAKBNLP 24 May 2024 Jadestone Energy (PM) Malaysia 50 -
Inc.
Mitra Energy (Vietnam
Nam Du) Pte
46/07 29 Jun 2035 Ltd Vietnam 100 100
Mitra Energy (Vietnam
Tho Chu) Pte
51 10 Jun 2040 Ltd Vietnam 100 100
Jadestone Energy
Lemang 17 Jan 2037 (Lemang) Pte Ltd Indonesia 90 90
Mitra Energy
(Philippines SC-57)
SC57 14 Sept 2055 Ltd Philippines -* 21
* In 2006, the Group executed an agreement with the Philippines
National Oil Company ("PNOC") to acquire a 21% working interest in
SC57. The acquisition required the approval of the Office of the
President of the Philippines and in December 2021 PNOC advised that
such approval will not be granted by the Philippines Department of
Energy. The Group is now seeking reimbursement from PNOC for costs
of approximately US$0.9 million which it incurred in relation to a
2008 seismic acquisition campaign. This is not recognised as a
receivable as at year end as it is not sufficiently certain that
the amount will be received.
26. DEFERRED TAX
The following are the deferred tax liabilities and assets
recognised by the Group and movements thereon.
Derivatives financial
instruments
Australian PRRT Malaysian PITA Tax depreciation USD'000 Total
USD'000 USD'000 USD'000 USD'000
As at 1 January 2020 13,215 - (60,445) (1,583) (48,813)
Credited to profit or
Loss (Note 17) 4,702 - 4,026 - 8,728
Credited to OCI - - - 1,583 1,583
--------------- --------------- ----------------- ---------------------- ---------
As at 31 December
2020 17,917 - (56,419) - (38,502)
Charged to profit or
loss (Note 17) (3,371) 1,135 (5,247) - (7,483)
Acquisition of PenMal
Assets (Note 19) - 4,166 - - 4,166
--------------- --------------- ----------------- ---------------------- ---------
As at 31 December
2021 14,546 5,301 (61,666) - (41,819)
=============== =============== ================= ====================== =========
The following is the analysis of the deferred tax balances
(after offset) for financial reporting purposes:
2021 2020
USD'000 USD'000
-------------------------- ---------- ----------
Deferred tax liabilities (67,097) (58,229)
Deferred tax assets 25,278 19,727
---------- ----------
(41,819) (38,502)
========== ==========
The Group has unutilised PRRT credits of approximately US$3.4
billion (2020: US$3.3 billion) available for offset against future
PRRT taxable profits in respect of the Montara field. The PRRT
credits remain effective throughout the production licence of
Montara. No deferred tax asset has been recognised in respect of
these PRRT credits, due to management's projections that there will
continue to be current augmentation of PRRT credits that are more
than sufficient to offset any PRRT tax to be paid. As PRRT credits
are utilised based on a last-in-first-out basis, the unutilised
PRRT credits of approximately US$3.4 billion (2020: US$3.3 billion)
will not be utilised given the forecasted augmentation, and are
therefore not recognised as a deferred tax asset.
27. INVENTORIES
2021 2020
USD'000 USD'000
------------------------------------------- --------- ---------
Materials and spares 12,011 21,245
Less: allowance for slow moving (Note 11) (2,060) (1,329)
--------- ---------
9,951 19,916
--------- ---------
Crude oil inventories 13,348 25,445
--------- ---------
23,299 45,361
========= =========
The cost of inventories recognised as an expense during the year
for lifted volumes, comprising 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, is US$200.4 million (2020: US$166.9
million).
28. TRADE AND OTHER RECEIVABLES
2021 2020
USD'000 USD'000
--------------------------------------------- -------- --------
Current assets
Trade receivables 9,143 106
Prepayments 3,770 2,012
Other receivables and deposits 13,281 4,273
Amount due from joint arrangement partners 2,203 -
(net)
Underlift crude oil inventories 6,855 -
GST/VAT receivables 2,699 719
-------- --------
37,951 7,110
Non-current assets
Other receivables
Acquisition of PenMal Assets (Note 19) 42,092 -
Change in asset restoration obligations (672) -
(Note 35)
Cess paid 306 -
-------- --------
41,726 -
Prepayment 2,000 -
VAT receivables 4,774 4,404
-------- --------
48,500 4,404
-------- --------
86,451 11,514
======== ========
Trade receivables arise from revenues generated in Australia and
Malaysia. The average credit period is 30 days (2020: 30 days). All
outstanding receivables as at 31 December 2021 and 2020 have been
fully recovered in 2022 and 2021, respectively.
Other receivables in current year consist of insurance claim
receivable of US$10.3 million on the well control claim for the
Skua 11 well workovers.
Amount due from joint arrangement partners represents cash calls
receivable from the Malaysian and Indonesian joint arrangement
partners, net of joint arrangement expenditures. The amount due
from the Malaysian joint arrangement partner 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 has been
fully recovered in 2022.
The amount due from the Indonesian joint arrangement partner is
unsecured, with a credit period of 7 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. An interest
at LIBOR plus 3% per annum will be imposed on the outstanding
amount, starting from the effective date of default.
Non-current other receivables represent the accumulated cess
payment paid to the Malaysian regulator for the operated licences.
The Malaysian require upstream operators to contribute periodic
cess payments to a cess abandonment fund throughout the production
life of the upstream oil and gas assets. This is to ensure there is
sufficient funds available for decommissioning expenditures
activities at the end of field life. The cess payment amount is
assessed based on the estimated future decommissioning
expenditures.
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 estimated to occur after 2022.
There are no trade receivables older than 30 days.
29. CASH AND BANK BALANCES
2021 2020
USD'000 USD'000
----------------------------------------------- --------- ---------
Cash and bank balances 117,865 89,441
Less: restricted cash - (8,445)
========= =========
Cash and cash equivalents in the consolidated
statement of cash flows 117,865 80,996
========= =========
Cash and bank balances in 2021 contains a restricted cash
balance of US$0.4 million and US$0.5 million in relation to a
deposit placed for bank guarantee with respect to the PenMal Assets
and Australian office building, respectively.
Restricted cash in 2020 included US$7.4 million related to the
Group's reserve based lending arrangement (Note 37). As part of the
agreement, the Group had to retain an aggregate amount of
principal, interest, fees and costs payable at each quarter-end in
a debt service reserve account ("DSRA"). The US$7.4 million was
deposited in the DSRA as at 31 December 2020. The DSRA was released
on 31 March 2021, upon the repayment of the final balance
outstanding on the loan. Restricted cash in 2020 also contained a
performance bank guarantee of US$1.0 million, placed with the
Indonesian regulator in relation to a joint study agreement
("JSA"). The amount was released to the Group during Q3 2021 upon
the completion of the JSA.
The restricted cash of US$10.0 million held by the Group in
2019, in support of a bank guarantee to a key supplier in respect
of Stag's FSO vessel, was released to the Group upon the
termination of the FSO vessel lease agreement in 2020.
30. SHARE CAPITAL
No. of USD'000
shares
------------------------------------- ------------- -----------
Issued and fully paid
As at 1 January 2020 461,042,811 466,573
Issued during the year 800,000 406
------------- -----------
As at 31 December 2020 461,842,811 466,979
Issued during the year 3,238,427 967
Capital reduction, at GBP0.499 each - (467,387)
As at 31 December 2021 465,081,238 559
============= ===========
On 4 May 2021, the High Court of Justice, Business and Property
Court, Companies Court in England and Wales approved the reduction
of share capital of the Company pursuant to section 648 of the Act
by cancelling the paid-up capital of the Company to the extent of
49.9 pence on each ordinary share of GBP0.50 in the issued share
capital of the Company. The effective date of the capital reduction
was 6 May 2021.
During the year, employee share options of 3,238,427 were
exercised and issued at an average price of GBGBP 0.33 per share
(2020: 800,000; GBGBP0.33 per share).
The Company has one class of ordinary share. Fully paid ordinary
shares carry one vote per share without restriction, and carry a
right to dividends as and when declared by the Company.
Prior to the internal reorganisation on 23 April 2021, Jadestone
Energy Inc. the former ultimate holding company, has issued
1,806,666 shares, resulting to the total outstanding number of
shares at 463,649,477 as at 23 April 2021. The Company has issued
1,431,761 shares post the completion of the internal
reorganisation.
31. DIVIDS
The parent company has sufficient distributable reserves to
declare dividends, despite the post-tax losses incurred during the
year. The dividends declared were in compliance with the Act.
The Directors plan to recommend a final 2021 dividend of 1.34 US
cents/share on 6 June 2022, equivalent to a total distribution of
US$9.0 million. The dividend will be paid in July 2022.
On 9 September 2021, the Directors declared a 2021 interim
dividend of 0.59 US cents/share, equivalent to 0.43 GB pence/share,
based on an exchange rate of 0.7257, equivalent to a total
distribution of US$2.8 million. The dividend was paid on 1 October
2021.
On 11 June 2021, the Directors declared the second interim 2020
dividend of 1.08 US cents/share, equivalent to 0.77 GB pence/share,
based on an exchange rate of 0.7087, equivalent to a total
distribution of US$5.0 million, or US$7.5 million in respect of
total 2020 dividends. The dividend was paid on 30 June 2021.
On 10 September 2020, the Directors declared the first 2020
interim dividend of 0.54 US cents/share, equivalent to 0.42 GB
pence/share, based on an exchange rate of 0.7708, equivalent to a
total distribution of US$2.5 million. The dividend was paid on 30
October 2020.
32. 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 (Note 2).
33. HEDGING RESERVES
2021 2020
USD'000 USD'000
-------------------------------------------- --------- ----------
At beginning of the year - (3,688)
Gain arising on changes in fair value of
hedging instruments during the
year - (26,093)
Income tax related to gain recognised in
other comprehensive income - 7,828
Net gain reclassified to profit or loss - 31,364
Income tax related to amounts reclassified
to profit or loss - (9,411)
---------- ----------
At end of the year - -
========== ==========
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. The Group's oil price
capped swap expired on 30 September 2020 and accordingly, all
cumulative deferred gains were recognised in the profit or
loss.
34. SHARE-BASED PAYMENTS RESERVE
The total expense arising from share-based payments of US$1.0
million (2020: US$1.1 million) was recognised as 'administrative
staff costs' (Note 8) in profit or loss for the year ended 31
December 2021.
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
Management has applied the Black-Scholes option-pricing model,
with the following assumptions, was used to estimate the fair value
of the options at the date of grant:
Options granted on
18 March 2021 27 April 2020
------------------------ ----------------- ----------------
Risk-free rate 0.49% to 0.61% 0.14% to 0.16%
Expected life 5.5 to 6.5 years 5.5 to 6.5 years
Expected volatility [1] 65.2% to 67.6% 42.7% to 43.9%
Share price GBGBP 0.65 GBGBP 0.44
Exercise price GBGBP 0.77 GBGBP 0.44
Expected dividends 1.79% 2.94%
34.2 Performance shares
The performance measures for performance shares incorporate a
balance of relative and absolute total shareholder return ("TSR")
on a 70:30 basis to reward outperformance vs. peers (relative TSR)
and alignment with shareholders (absolute TSR).
Relative TSR : measured against the TSR of peer companies; the
size of the pay out 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
18 March 2021 27 April 2020
----------------------------- ---------------- --------------
Risk-free rate 0.06% 0.08%
Expected volatility [2] 51.4% 66.0%
Share price GBGBP 0.77 GBGBP 0.44
Exercise price N/A N/A
Expected dividends 2.64% 2.80%
Post-vesting withdrawal date N/A N/A
Early exercise assumption N/A 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
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
18 March 2021 27 April 2020
------------------- ---------------- -------------
Risk-free rate 0.08% 0.08%
Share price GBGBP 0.77 GBGBP 0.44
Expected dividends 2.64% 2.80%
The following table summarises the options/shares under the LTI
plans outstanding and exercisable as at 31 December 2021:
Shares Options
--------------- ---------------
Weighted Weighted
average average Number
Performance Restricted Number of exercise remaining of options
shares shares options price GB GBP contract life exercisable
---------------- --------------- --------------- --------------- --------------- --------------- ---------------
As at 1 January
2020 - - 19,867,842 0.39 8.21 7,019,480
New
options/share
awards issued 695,200 101,063 6,525,000 0.44 9.83 -
Vested during
the
year - - - 0.38 7.20 6,193,347
Exercised during
the
year - - (800,000) 0.33 - (800,000)
Cancelled during
the
year (12,000) - (400,000) 0.73 - (200,000)
--------------- --------------- --------------- --------------- --------------- ---------------
As at 31
December
2020 683,200 101,063 25,192,842 0.40 7.78 12,212,827
New
options/share
awards issued 1,136,512 50,570 2,852,631 0.77 9.21 -
Vested during
the
year - - - 0.42 6.92 3,776,672
Exercised during
the
year - - (3,238,427) 0.33 - (3,238,427)
Cancelled during
the
year (328,058) - (3,690,244) 0.46 - (1,539,905)
--------------- --------------- --------------- --------------- --------------- ---------------
As at 31
December
2021 1,491,654 151,633 21,116,802 0.45 7.15 11,211,167
=============== =============== =============== =============== =============== ===============
35. PROVISIONS
Asset
restoration Contingent Employees Incentive
obligations Stag payments benefits scheme
(a) FSO (c) (d) (e) Others Total
USD'000 (b) USD'000 USD'000 USD'000 USD'000 USD'000
USD'000
------------------ ----------- ----------- ----------- ---------- ---------- --------- -----------
As at 1
January
2020 275,422 4,996 359 851 1,312 - 282,940
Charge to
profit
or loss - - - 67 1,304 1,905 3,276
Acquisition
of
Lemang PSC 2,741 - 4,436 - - - 7,177
Accretion
expense
(Note 15) 6,312 51 - - - - 6,363
Changes in
discount
rate
assumptions
(Note 22) (725) - - - - - (725)
Utilised - - - (22) (821) - (843)
Fair value
adjustment
(Note 16) - - (359) - - - (359)
Reversal
(Note 14) - (5,047) - - - - (5,047)
----------- ----------- ----------
As at
31 December
2020 283,750 - 4,436 896 1,795 1,905 292,782
Charge to
profit
or loss - - - - - 202 202
Acquisition
of
PenMal Assets
(Note 19) 91,552 - 4,305 - - - 95,857
Accretion
expense
(Note 15) 5,920 - - - - - 5,920
Changes in
discount
rate
assumptions
(Notes 21,
22
and 28) 23,178 - - - - - 23,178
Payment/Utilised - - (3,000) (50) (778) (1,516) (5,344)
Fair value
adjustment
(Note 15) - - 438 - - - 438
Reversal
(Note 14) - - - - - (389) (389)
----------- ----------- ----------- ---------- ---------- --------- -----------
As at
31 December
2021 404,400 - 6,179 846 1,017 202 412,644
=========== =========== =========== ========== ========== ========= ===========
Asset
restoration Contingent Employees Incentive
obligations Stag payments benefits scheme
(a) FSO (c) (d) (e) Others Total
USD'000 (b) USD'000 USD'000 USD'000 USD'000 USD'000
USD'000
-------------- ------------ --------- ------------ ----------- ----------- --------- ---------
As at
31 December
2020
Current - - - 858 1,795 1,905 4,558
Non-current 283,750 - 4,436 38 - - 288,224
------------ --------- ------------ ----------- ----------- --------- ---------
283,750 - 4,436 896 1,795 1,905 292,782
============ ========= ============ =========== =========== ========= =========
As at
31 December
2021
Current - - - 728 1,017 202 1,947
Non-current 404,400 - 6,179 118 - - 410,697
------------ --------- ------------ ----------- ----------- --------- ---------
404,400 - 6,179 846 1,017 202 412,644
============ ========= ============ =========== =========== ========= =========
(a) The Group's asset restoration obligations ("ARO") comprise
the future estimated costs to decommission each of the Montara,
Stag, Lemang PSC and PenMal 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 and
PenMal Assets have been escalated to the estimated date at which
the expenditure would be incurred, at an assumed blended inflation
rate of 2.06%, 2.12%, 2.82% and range of 2.05% to 2.07%,
respectively (2020: Montara: 1.52%; Stag: 1.48%; Lemang PSC:
2.54%). 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 and PenMal Assets has then been calculated based
on blended risk-free rates of 1.77%, 1.91%, 5.96% and a range of
2.81% to 3.24%, respectively (2020: Montara: 1.72%; Stag: 1.78%;
and Lemang PSC: 5.86%). The base estimate ARO for Montara, Stag and
Lemang PSC remains largely unchanged from 2020. The ARO of PenMal
Assets was assessed in 2021, based on the existing facilities and
wells acquired and required to be decommissioned at the end of
field life.
Management expects decommissioning expenditures to be incurred
from 2024, 2032, 2034 and 2035 onwards for PenMal Assets, Montara,
Lemang PSC and Stag, respectively.
In 2019, Jadestone Energy (Eagle) Pty Ltd, a wholly owned
subsidiary of the Company entered into a deed poll with the
Australian Government with regard to the requirements of
maintaining sufficient financial capacity to ensure Montara's asset
restoration obligations can be met when due. The deed states that
the Group is required to provide a financial security in favour of
the Australian Government when the aggregate remaining net after
tax cash flow of the Group is 1.25 times or below the Group's
estimated future decommissioning costs.
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 cess payment amount is assessed based on
the estimated future decommissioning expenditures. The cess payment
paid for non-operated licences reduces the asset restoration
liability.
(b) The provision for Stag FSO was reversed in 2020 following
the termination of the FSO vessel lease.
(c) The contingent payment of US$1.4 million represented the
fair value of one contingent payment payable to SapuraOMV for the
PenMal Assets acquisition, based on the outlook of Brent crude oil
prices in 2022 (Note 19). The contingent payment (if triggered)
will need to be made in January 2023 and accordingly has been
classified as non-current liability.
The fair value of the contingent payments payable to Mandala
Energy Lemang Pte Ltd for the Lemang PSC acquisition are valued at
US$4.8 million as at 31 December 2021 (2020: US$4.4 million) for
the trigger events as disclosed in Note 20.
The contingent payment of US$0.4 million for the Montara
acquisition was derecognised in 2020 as the liability failed to
crystallise. The Group has not recognised other contingent payments
associated with Montara acquisition as the management considers the
probability of outflow is remote.
(d) 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.
(e) The Group's performance pay incentive scheme is based on the
Group's and employees' performance, and is payable annually to
employees at variable percentages of their annual wage.
36. LEASE LIABILITIES
2021 2020
USD'000 USD'000
---------------------------------------- -------- ---------
Presented as:
Non-current 4,504 13,305
Current 11,161 12,478
-------- ---------
15,665 25,783
======== =========
Maturity analysis of lease liabilities
based on undiscounted gross cash
flows:
Year 1 12,247 13,448
Year 2 3,440 11,239
Year 3 209 2,803
Year 4 221 -
Year 5 233 -
Future interest charge (685) (1,707)
-------- ---------
15,665 25,783
======== =========
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.
37. BORROWINGS
2021 2020
USD'000 USD'000
--------------------------------- --------- --------
Secured borrowings
Reserve based lending facility - 7,296
========== ========
At the end of Q1 2021, the Group fully repaid its reserve based
lending facility, making a final principal repayment of US$7.3
million (2020: US$42.8 million) and interest of US$0.1 million
(2020: US$1.4 million).
The loan incurred interest at LIBOR plus 3% (2020: LIBOR plus
3%).
38. RECONCILIATION OF LIABILITIES ARISING FROM FINANCING
ACTIVITIES
The table below details changes in the Group's liabilities
arising from financing activities, including both cash and non-cash
changes. Liabilities arising from financing activities are those
for which cash flows were, or future cash flows will be, classified
in the Group's consolidated statement of cash flows, as cash flows
from financing activities.
The cash flows represent the repayment of borrowings and lease
liabilities, in the consolidated statement of cash flows.
Reserved based lending facility
USD'000 Lease liabilities
USD'000
---------------------------- ------------------------------- --------------------
As at 1 January 2020 49,123 62,272
Financing cash flows (42,766) (16,603)
New lease liabilities - 891
Termination of leases - (20,777)
Interest paid (1,427) (1,959)
Non-cash changes - interest 2,366 1,959
------------------------------- --------------------
As at 31 December 2020 7,296 25,783
Financing cash flows (7,296) (12,972)
New lease liabilities - 2,854
Interest paid 150 (1,222)
Non-cash changes - interest (150) 1,222
------------------------------- --------------------
As at 31 December 2021 - 15,665
=============================== ====================
39. TRADE AND OTHER PAYABLES
2021 2020
USD'000 USD'000
------------------------------------------ -------- --------
Trade payables 26,847 10,131
Other payables 7,627 2,004
Accruals 29,699 20,047
Contingent payment 3,000 -
Malaysian supplementary payment payables 1,907 -
GST/VAT payables 10 10
-------- --------
69,090 32,192
======== ========
Trade and other payables and accruals principally comprise
amounts outstanding for trade and non-trade purchases and ongoing
costs. The average credit period taken for purchases is 30 days
(2020: less than 30) days. For most suppliers, no interest is
charged on the payables in the first 30 days from the date of
invoice. Thereafter, interest may be charged on outstanding
balances at varying rates of interest. The Group has financial risk
management policies in place to ensure that all payables are
settled within the pre-agreed credit terms.
The contingent payment of US$3.0 million payable to SapuraOMV
arose from the acquisition of the PenMal Assets (Note 19). The
contingent payment was paid in January 2022 as the annual average
Brent crude price in 2021 exceeded US$65/bbl.
40. DERIVATIVE FINANCIAL INSTRUMENTS
The Group uses derivatives to manage its exposure to oil price
fluctuations. Oil hedges are undertaken using swaps, and in some
cases, call options. All contracts are referenced to Dated Brent
oil prices. During the year, the Group entered into commodity swaps
that are carried at fair value through profit or loss ("FVTPL").
The commodity swaps expired at the end of June 2021 and the Group
has not entered into any further commodity swaps. Accordingly,
there are no outstanding derivative contracts for the year ended 31
December 2021.
2021 2020
USD'000 USD'000
---------------------------------- --------- --------
Derivative financial liabilities
Carried at FVTPL
Commodity swaps - (471)
========== ========
The fair values of the commodity swaps in 2020 were classified
as Level 2 and calculated using market prices that the Group would
pay or receive to settle those swap contracts.
The following is a summary of the Group's outstanding derivative
contracts in 2020:
Fair value asset
at 31 December
2020
Type of contracts Hedge USD'000
Contract quantity Terms Contract price classification
------------------ ------------------ ------------------ ------------------ ------------------- -----------------
Contracts designated as cash flow hedges
27% of Group's Commodity capped Oct 2018 - US$78.26/bbl for Cash flow -
actual 2PD swap: swap Sep 2020 Q4 2018,
production component US$71.72/bbl for
2019 and
US$68.45/bbl for
the nine months to
30
September 2020
67% of swapped Commodity capped Jan 2019 - US$80.00/bbl for Cash flow -
barrels in 2019 swap: call Sep 2020 the nine months to
and in the nine component 30 September 2019,
months to 30 then US$85.00/bbl
September 2020 to September 2020
Contracts that are not designated in hedge accounting relationships
31% of Group's
anticipated
planned 2P
production from
January to March
2021 Commodity swap Jan - March 2021 US$49.00/bbl FVTPL (471)
The Group's October 2018 to September 2020 capped swap programme
was designated as a cash flow hedge. Critical terms of the capped
swap (i.e., the notional amount, life and underlying oil price
benchmark) and the corresponding Montara hedged sales were highly
similar. The Group performed a qualitative assessment of the
effectiveness of the capped swap contracts and concluded that the
value of the capped swap and the value of the corresponding hedged
items was systematically changed in opposite directions in response
to movements in the underlying commodity prices.
There was, however, a source of ineffectiveness in the capped
swap arrangement, arising from the slight difference in the timing
of Montara's production and the settlement of the capped swap
arrangement versus the crude sales. The overall change in value in
the capped swap transaction arose from the hedge ineffectiveness
amounted to a net loss of approximately US$4,000 in 2020, and was
included in the statement of profit or loss within "other expenses"
(Note 11).
The following table details the information regarding the hedged
items of the commodity capped swap contracts.
Hedged items
Balance in cash flow hedge
reserve arising from hedging
Change in value used for relationships for which hedge
calculating hedge Balance in cash flow hedge accounting
ineffectiveness reserve for continuing hedges is no longer applied
USD'000 USD'000 USD'000
---------------- -------------------------------- -------------------------------- --------------------------------
2020
Cash flow hedges
Forecast sales 4 - -
================================ ================================ ================================
The following table details the effectiveness of the hedging
relationships and the amounts reclassified from hedging reserve to
profit or loss:
Amount
reclassified to
Amount of hedge Line item in profit profit or loss due Line item in profit
Current period ineffectiveness or loss in which to hedged item or loss in which
hedging gain recognised in hedge affecting profit reclassification
recognised in OCI profit or loss ineffectiveness is or loss adjustment is
USD'000 USD'000 included USD'000 included
-------------- -------------------
2020
Cash flow hedges
Forecast sales 18,265 4 Other expenses 31,360 Revenue
41. FINANCIAL INSTRUMENTS, FINANCIAL RISKS AND CAPITAL
MANAGEMENT
Financial assets and liabilities
Current assets and liabilities
Management considers 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.
2021 2020
USD'000 USD'000
---------------------------------------------- --------- --------
Financial assets
At amortised cost
Trade and other receivables, excluding
prepayments and GST/VAT
receivables 31,482 4,379
Restricted cash - 8,445
Cash and bank balances 117,865 80,996
--------- --------
149,347 93,820
2021 2020
USD'000 USD'000
---------------------------------------------- --------- --------
Financial liabilities
At amortised cost
Trade and other payables, excluding GST/VAT
payables 69,080 32,182
Lease liabilities 15,665 25,783
Borrowings - 7,296
Contingent consideration for Lemang PSC
acquisition 4,750 4,436
Contingent consideration for PenMal Assets 1,429 -
acquisition
Derivative instruments carried at FVTPL - 471
--------- --------
90,924 70,168
========= ========
Fair values are based on management's best estimates, after
consideration of current market conditions. The estimates are
subjective and involve judgment, and as such are not necessarily
indicative of the amount that the Group may incur in actual market
transactions.
Commodity price risk
The Group's earnings are affected by changes in oil prices. The
Group manages this risk by monitoring oil prices and entering into
commodity hedges against fluctuations in oil prices where
considered appropriate.
Montara
The Group hedged 50% of its planned production volumes for the
24 months to 30 September 2020. The hedge was a capped swap,
providing downside price protection via swaps, while allowing for
participation in higher commodity prices via purchased call
options. The call strike was set at US$80/bbl for the nine months
to 30 September 2019 and US$85/bbl for the twelve months to
September 2020. The swap price was set at US$78.26/bbl for Q4 2018,
US$71.72/bbl for 2019 and US$68.45/bbl for the nine months to
September 2020. Approximately two thirds of the swapped barrels in
2019 and 2020 had upside price participation via purchased calls.
The effective date of the hedge contracts was 1 October 2018.
In December 2020, the Group entered into a commodity swap
arrangement to hedge 31% of its planned production volumes from
January to March 2021, to provide downside oil price protection.
The swap price was set at US$49/bbl.
On 16 February 2021, the Group entered into a commodity swap
arrangement to further hedge 31% of its planned production volumes
from April to June 2021. The swap price was set at
US$61.40/bbl.
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 profit/(loss) 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 forecasted estimates.
Effect on Effect on Effect on Effect on
the other the other
result comprehensive result comprehensive
before tax income before before tax income before
for the tax for the tax
Gain or loss year ended for the year year ended for the year
31 December ended 31 December ended
2021 31 December 2020 31 December
USD'000 2021 USD'000 2020
USD'000 USD'000
Increase by
10% - - (1,348) -
Decrease by
10% - - 1,348 -
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 April 2020, the Group entered into a series of forward
exchange contracts under which it contracted to purchase AU$10.0
million per month, from May to November 2020, at a fixed forward
AU$/US$ exchange rate of 0.6344.
In addition to US Dollar, the Group transacts in various
currencies, including Australian Dollar, Malaysian Ringgit,
Vietnamese Dong, Indonesian Rupiah, Singapore Dollar, New Zealand
Dollar and British Pound Sterling.
Foreign currency sensitivity
Material foreign denominated balances were as follows:
2021 2020
USD'000 USD'000
--------
Cash and bank balances
Australian Dollars 6,027 8,043
Malaysian Ringgit 4,622 -
Trade and other receivables
Australian Dollars 2,706 1,547
Malaysian Ringgit 48 -
Trade and other payables
Australian Dollars 43,219 21,233
Malaysian Ringgit 15,094 -
A strengthening/weakening of the Australian dollar and Malaysian
Ringgit by 10%, versus the functional currency of the Group, is
estimated to result in the net carrying amount of Group's financial
assets and financial liabilities as at year end
decreasing/increasing by approximately US$4.5 million (2020: US$1.2
million), and which would be charged/credited to the consolidated
statement of profit or loss.
Interest rate risk
The Group's interest rate exposure arises from some of its cash
and bank balances. The Group's other financial instruments are
non-interest bearing or fixed rate, and are therefore not subject
to interest rate risk.
The Group holds some of its cash in interest bearing accounts
and short-term deposits. Interest rates currently received are at
relatively low levels. Accordingly, a downward interest rate
movement would not cause significant exposure to the Group.
On 2 August 2018, the Group entered into a reserve based lending
agreement with the Commonwealth Bank of Australia and Société
Générale to borrow US$120.0 million, repayable quarterly to 31
March 2021. The loan was fully drawn down on 28 September 2018 and
incurred interest at LIBOR plus 3%. The loan incurred establishment
and other costs of US$3.2 million, which were offset against the
proceeds received.
Based on the carrying value of the reserve based loan as at 31
December 2020, if interest rates had increased or decreased by 1%
and all other variables remained constant, the impact on the
Group's quarterly net income/(loss) before tax would be immaterial.
The loan was fully repaid on 31 March 2021.
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 customers, 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:
Basis for recognising
expected credit losses
Category Description ("ECL")
Performing The counterparty has a low 12-month ECL
risk of default and does not
have any past due amounts.
Doubtful Amount is > 30 days past due Lifetime ECL - not credit-impaired
or there has been a significant
increase in credit risk since
initial recognition.
In default Amount is > 90 days past due Lifetime ECL - credit-impaired
or there is evidence indicating
the asset is credit-impaired.
Write-off There is evidence indicating Amount is written off
that the debtor is in severe
financial difficulty and the
Group has no realistic prospect
of recovery.
The table below details the credit quality of the Group's
financial assets and other items, as well as maximum exposure to
credit risk by credit risk rating grades:
Gross
12-month carrying
External Internal ("12m") amount Loss Net carrying
credit credit or (i) allowance amount
Note rating rating lifetime USD'000 USD'000 USD'000
ECL
2021
Cash and bank
balances 29 n.a Performing 12m ECL 117,865 -* 117,865
Lifetime
Trade receivables 28 n.a (i) ECL 9,143 -* 9,143
Other receivables 28 n.a Performing 12m ECL 13,281 -* 13,281
Amount due
from
joint
arrangement
partners 28 n.a Performing 12m ECL 2,203 -* 2,203
2020
Cash and bank
balances 29 n.a Performing 12m ECL 89,441 -* 89,441
Lifetime
Trade receivables 28 n.a (i) ECL 106 -* 106
Other receivables 28 n.a Performing 12m ECL 4,273 -* 4,273
* 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 2021, total trade receivables amounted to
US$9.1 million (2020: US$0.1 million). The balance in 2021 and 2020
had been fully recovered in 2022 and 2021, 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 is limited because
counterparties are banks with high credit ratings assigned by
international credit rating agencies. The banks are also regulated
locally, and with no history of default.
The maximum credit risk exposure relating to financial assets is
represented by their carrying value as at the reporting date.
Liquidity risk
Liquidity risk is the risk that the Group will not be able to
meet all of its financial obligations as they become due. This
includes the risk that the Group cannot generate sufficient cash
flow from producing assets, or is unable to raise further capital
in order to meet its obligations.
The Group manages its liquidity risk by optimising the positive
free cash flow from its producing assets, on-going cost reduction
initiatives, merger and acquisition strategies, and bank balances
on hand.
The Group's net loss after tax for the year was US$13.7 million
(2020: US$60.2 million, inclusive of non-cash SC56 impairment of
US$50.4 million). Operating cash flows before movements in working
capital and net cash generated from operating activities for the
year ended 31 December 2021 was US$96.6 million and US$102.1
million (2020: US$86.9 million and US$84.6 million) respectively.
The Group's net current assets remained positive at US$80.0 million
as at 31 December 2021 (2020: US$79.5 million).
The Group believes it has sufficient liquidity to meet all
reasonable scenarios of operating and financial performance for the
next 18 months.
Non-derivative financial liabilities
The following table details the expected contractual maturity
for non-derivative financial liabilities with agreed repayment
periods. The table below has been drawn up 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. The adjustment column represents the estimated
future cash flows attributable to the instrument included in the
maturity analysis, which are not included in the carrying amount of
the financial liabilities on the consolidated statement of
financial position, namely interest expense.
Weighted average
effective On demand or within Within 2 to 5 More than
interest rate 1 year years 5 years Adjustments Total
% USD'000 USD'000 USD'000 USD'000 USD'000
2021
Non-interest bearing -
Trade and other
payables - 69,080 - - - 69,080
Contingent
consideration for
Lemang PSC
acquisition - - 4,750 - - 4,750
Contingent
Consideration for
PenMal Assets
acquisition - - 1,429 - - 1,429
Fixed interest rate
instruments
Lease liabilities 5.847 12,247 4,103 - (685) 15,665
81,327 10,282 - (685) 90,924
Weighted average
effective On demand or within Within 2 to 5 More than
interest rate 1 year years 5 years Adjustments Total
% USD'000 USD'000 USD'000 USD'000 USD'000
2020
Non-interest bearing
Trade and other
payables - 32,182 - - - 32,182
Contingent
consideration for
Lemang PSC
acquisition - - 4,436 - - 4,436
Fixed interest rate
instruments
Lease liabilities 6.049 13,448 14,042 - (1,707) 25,783
Variable interest rate
instruments
Borrowings 7.570 7,445 - - (149) 7,296
53,075 18,478 - (1,856) 69,697
Non-derivative financial assets
The following table details the expected maturity for
non-derivative financial assets. The inclusion of information on
non-derivative financial assets is necessary in order to understand
the Group's liquidity risk management, as the Group's liquidity
risk is managed on a net asset and liability basis. The table has
been drawn up based on the undiscounted contractual maturities of
the financial assets, including interest that will be earned on
those assets, except where the Group anticipates that the cash flow
will occur in a different period. The adjustment column represents
the estimated future cash flows attributable to the instrument
included in the maturity analysis, which are not included in the
carrying amount of the financial assets on the consolidated
statement of financial position, namely interest income.
Weighted
average On demand Within
effective or within 2 to 5
interest rate 1 year years Adjustments Total
% USD'000 USD'000 USD'000 USD'000
2021
Non-interest bearing
Trade and other
receivables, excluding
prepayments and
GST/VAT receivables - 31,482 - - 31,482
Variable interest rate
instruments
Cash and bank balances -* 117,865 - -* 117,865
149,347 - -* 149,347
Weighted
average On demand Within
effective or within 2 to 5
interest rate 1 year years Adjustments Total
% USD'000 USD'000 USD'000 USD'000
2020
Non-interest bearing
Trade and other
receivables, excluding
prepayments and
GST/VAT receivables - 4,379 - - 4,379
Variable interest rate
instruments
Restricted cash -* 8,445 - -* 8,445
Cash and bank balances -* 80,996 - -* 80,996
93,820 - -* 93,820
* The effect of interest is not material.
Capital management
The Group manages its capital structure and makes adjustments to
it, based on the funds available to the Group, in order to support
the acquisition, exploration and development of resource properties
and the ongoing operations of its producing assets. Given the
nature of the Group's activities, the Board of Directors works with
management to ensure that capital is managed effectively, and the
business has a sustainable future.
The capital structure of the Group represents the equity of the
Group, comprising share capital, merger reserve and share-based
payment reserve, as disclosed in Notes 30, 32 and 34,
respectively.
To carry-out planned asset acquisitions, exploration and
development, and to pay for administrative costs, the Group may
utilise excess cash generated from its ongoing operations and may
utilise its existing working capital, and will work to raise
additional funds should that be necessary.
Management reviews its capital management approach on an ongoing
basis and believes that this approach, given the relative size of
the Group, is reasonable. There were no changes in the Group's
approach to capital management during the year ended 31 December
2021. The Group is not subject to externally imposed capital
requirements.
2021 2020
USD'000 USD'000
--------------------------- ---------
Borrowings - (7,296)
Cash and cash equivalents 117,865 81,996
Restricted cash - 7,445
Cash less borrowings 117,865 82,145
Borrowings balance in 2020 related to the reserve based lending
facility that was fully repaid in March 2021. The borrowings of
US$7.3 million was based on the effective interest method financing
costs, and excludes derivatives, as detailed in Note 37. Cash and
cash equivalents in 2020 included the Montara assets' minimum
working capital cash balance of US$15.0 million required under the
reserve based lending facility, while restricted cash in 2020
comprised the US$7.4 million in the DSRA. The restricted cash of
US$7.4 million in 2020 excluded a US$1.0 million cash
collateralised for a bank guarantee placed with the Indonesian
regulator in respect of the JSA entered by the Group in Indonesia
because the bank guarantee was removable and can then be used to
fund the business.
The Group's overall strategy remains unchanged from 2020.
Fair value measurements
The Group discloses fair value measurements by level of the
following fair value measurement hierarchy:
i. Quoted prices (unadjusted) in active markets for identical
assets or liabilities (Level 1);
ii. Inputs, other than quoted prices included within Level 1,
that are observable for the asset or liability, either directly or
indirectly (Level 2); and
iii. Inputs for the asset or liability that are not based on
observable market data (unobservable inputs) (Level 3).
Relationship
of
Fair value (USD'000) as at Fair Valuation Significant unobservable
2021 2020
Financial technique(s)
assets/financial value and key unobservable inputs to
liabilities Assets Liabilities Assets Liabilities hierarchy input(s) input(s) fair value
Derivative financial instruments
1) Oil price - - - 471 Level 2 T hird party n.a. n.a.
swaps and calls val uations
(Note 40) based on
market
comparable
information.
Others - contingent consideration from Lemang PSC
acquisition
Based on the
nature and
the
likelihood
of the
occurrence of
the trigger
events. Fair
value is Gas
estimated, production
taking into schedule
consideration could
the estimated be changed
future gas depending on
production future gas
schedule, contract
forecasted negotiations.
Dated Brent A change in
oil prices Expected gas
and future oil production
Saudi CP price schedule or
prices and volatility significant
respective is based on increase in
price an analysis Dated Brent
volatility of oil prices
at the end of Dated Brent and Saudi CP
the reporting oil price and prices
period, as Saudi CP would result
well price in a
as the effect movements significant
2) Contingent of the time as at increase in
consideration value of acquisition the fair
(Note 35) - 4,750 - 4,436 Level 3 money. date. value.
Relationship
of
Fair value (USD'000) as at Fair Valuation Significant unobservable
2021 2020
Financial technique(s)
assets/financial value and key unobservable inputs to
liabilities Assets Liabilities Assets Liabilities hierarchy input(s) input(s) fair value
Others - contingent consideration from PenMal Assets acquisition
Based on the
nature and
the
likelihood of
occurrence of
the trigger
event. Fair
value is
estimated
using future
Dated Brent
oil
price Expected
forecasts future oil
at the end of price A slight
the reporting volatility is increase in
period, based on Dated Brent
taking an analysis oil prices
into account of Dated would
the time Brent oil result in a
value price significant
3) Contingent of money and movements as increase in
consideration volatility of at the the fair
(Notes 19, 35 oil Acquisition value and
and 39) - 4,429 - - Level 3 prices. Date. vice versa.
42. SEGMENT INFORMATION
Information reported to the Group's Chief Executive Officer (the
chief operating decision maker) for the purposes of resource
allocation is focused on two reportable/business segments driven by
different types of activities within the upstream oil and gas value
chain, namely producing assets and secondly development and
exploration assets. The geographic focus of the business is on
Southeast Asia ("SEA") and Australia.
Revenue and non-current assets information based on the
geographical location of assets respectively are as follows:
Producing Exploration/
assets development
Australia SEA SEA Corporate Total
USD'000 USD'000 USD'000 USD'000 USD'000
2021
Revenue
Liquids revenue 293,566 45,644 - - 339,210
Gas revenue - 984 - - 984
293,566 46,628 - - 340,194
Production cost (182,001) (24,522) - - (206,523)
DD&A (75,848) (3,621) (281) (465) (80,215)
Administrative staff
costs (13,364) (1,433) (1,612) (8,659) (25,068)
Other expenses (14,970) (2,466) (5,875) (2,870) (26,181)
Other income 7,038 9 76 559 7,682
Finance costs (7,452) (875) (503) (245) (9,075)
Other financial gains - - 266 - 266
Profit/(Loss) before tax 6,969 13,720 (7,929) (11,680) 1,080
Additions to non-
current assets 57,130 64,117 4,744 183 126,174
Non-current assets 366,959 59,532 90,938 719 518,148
2020
Revenue
Liquids revenue 217,938 - - - 217,938
Production cost (105,338) - - - (105,338)
DD&A (84,024) - (110) (508) (84,642)
Administrative staff
costs (10,029) - (2,228) (9,646) (21,903)
Other expenses (15,068) - (9,690) (2,160) (26,918)
Impairment of assets - - (50,455) - (50,455)
Other income 14,292 - 1 12,083 26,376
Finance costs (12,625) - (29) (1) (12,655)
Other financial gains 359 - - - 359
Profit/(Loss) before tax 5,505 - (62,511) (232) (57,238)
Additions to non-
current assets 11,162 - 27,706 914 39,782
Non-current assets 349,292 - 97,838 945 448,075
Non-current assets as shown here comprises oil and gas
properties, intangible exploration assets, right-of-use assets,
other receivables, restricted cash and plant and equipment used in
corporate offices. Deferred tax assets are excluded from the
segmental note but included in the Group's consolidated statement
of financial position.
Revenues arising from producing assets arose from sales to the
Group's respective sole customer in Australia and Malaysia.
43. FINANCIAL CAPITAL COMMITMENTS
Certain PSCs and service concessions have firm capital
commitments. The Group has the following outstanding minimum
commitments:
SEA portfolio PSC operational commitments
2021 2020
USD'000 USD'000
-------------------------
Not later than one year 400 10,000
One to five years 12,000 2,000
More than 5 years 10,700 10,684
23,100 23,084
The SEA portfolio PSC operational commitments as at 31 December
2021 amounted to US$17.3 million (2020: US$ 17.3 million), and
relates to the minimum work commitment outstanding for the Block
46/07 PSC and the Lemang PSC. The operational commitments also
include training commitment of US$5.8 million (2020: US$5.8
million), for the Block 46/07 PSC, Block 51 PSC and the PenMal
Assets.
Work commitment
Under the terms of the Block 46/07 PSC, Jadestone is committed
to drill one more appraisal well on the block. The Group plans to
drill an appraisal well on the Nam Du field to facilitate
transition of 3C resource to 2C status. This well would be retained
for future use as a Nam Du gas producer. Following the Group's
announcement to delay the project in 2020, the Group obtained
Vietnam Government approval on 14 September 2021 for a further
extension of three years to 29 June 2024 in order to align drilling
of the appraisal well with development of Nam Du/U Minh.
Discussions are continuing with Petrovietnam to agree a gas
production profile for the development, as a precursor to a gas
sales contract, and ultimately attaining government sanction for
the field development.
As part of the acquisition under the terms of the Lemang PSC,
the Group, as the operator, has inherited unfulfilled work
commitments of US$7.3 million consisting of one exploration well
and a 3D seismic programme. The work commitments should have been
completed during the exploration phase of the PSC by the previous
owner. It has been agreed with the Indonesian regulator that the
work commitments can be completed after first gas in 2024 but
before the end of 2026.
Training commitment
Under the terms of the Block 46/07 PSC and Block 51 PSC, the
Group commits to pay an annual training commitment amount of US$0.4
million to Petrovietnam until the expiration of the respective PSC
licence. The training commitment amount is for the purpose of
developing the local employees in the oil and gas industry.
As part of the acquisition under the terms of the PenMal Assets,
the Group has inherited net training commitments of US$0.3 million
and US$0.1 million for PM323 PSC and PM318 PSC, respectively. Funds
provided with respect to this training commitment are applied to
the development of local employees in the oil and gas industry. The
training commitments are required to be completed before the
expiration of the respective PSC.
Capital commitments
The Group has the following capital commitments for expenditure
that were contracted for at the end of the reporting year but not
recognised as liabilities for Stag and Montara:
2021 2020
USD'000 USD'000
------------------------- -------- --------
Not later than one year 5,254 8,977
======== ========
The capital commitment of US$5.3 million as at 2021 year end
predominately arose from long leads for 50H and 51H drilling
programme at Stag, which is scheduled to occur in the middle of
2022. The 2020 capital commitment of US$9.0 million mainly related
to drilling of Montara H6 infill well and Skua 12 well planning
expenditure.
44. CONTINGENT LIABILITY
Legal disputes
The Group has an ongoing legal dispute with a third party
contractor over a long term contract. The Group disputes the claims
from the third party contractor and requested a refund for an
overpaid milestone payment against the contractor. The contractor
commenced a legal proceeding against the Group in the Singapore
High Court that ruled in favour of Jadestone. Following, the
contractor appealed the High Court decision and the appeal was
dismissed. The contractor may initiate arbitration proceeding
against Jadestone in the future but has not commenced an action as
at the reporting date. The Group may be liable for US$6.0 million
in the future, if the contractor initiates the arbitration
proceeding and succeed. At this time, the management does not
consider it to be probable and no provision is recognised in the
financial statements.
45. E VENTS AFTER THE OF THE REPORTING PERIOD
Russian military actions
On 24 February 2022 Russia commenced military actions against
Ukraine. Following, multiple countries around the world have
imposed different forms of sanctions against Russia. The Group has
assessed the sanctions imposed by the countries that the Group is
operating within and concluded that the sanctions had no impact to
the operations of the Group.
The Group is monitoring the rapidly evolving sanctions situation
and will perform regular assessments to identify any potential
impact in the future.
Suspension of PenMal Assets's non-operated floating production
storage and offloading ("FPSO")
In February 2022, the Bunga Kertas FPSO, deployed at the PenMal
Assets' non-operated assets, had its class suspended, resulting in
the cessation of production. The operator of the non-operated
assets anticipates that the FPSO will have its class reinstated by
July 2022 and production will be resumed by then accordingly.
Net Zero greenhouse gas emissions target update
On 1 June 2022, the Company announced its commitment to Net Zero
Scope 1 and 2 greenhouse gas emissions from its operated assets by
2040. A key element of the Company's Net Zero commitment will be
the development of detailed emissions reduction roadmaps for its
operated assets, which will be published in 2023. Jadestone's
corporate strategy of maximising recovery from existing fields
while minimising their emissions, and a move towards more gas in
the portfolio over time, is both responsible and appropriate in the
context of managing climate change. This also strikes the right
balance in delivering secure and affordable energy in parts of
Southeast Asia where either an energy shortage exists or where coal
may be used as an alternative. Jadestone believes it can play an
important role during this period of energy transition, while also
demonstrating resilience and longevity to its business. It is not
possible to estimate the financial effect at this time.
46. RELATED PARTY TRANSACTIONS
Internal reorganisation
Pursuant to the internal reorganisation, on 23 April 2021, a
transfer of beneficial interest agreement was entered into between
Jadestone Energy Inc. ("JEI"), Jadestone Energy Holdings Limited
("JEHL") and Daniel Young, Chief Financial Officer. Under the
transfer of beneficial interest agreement, JEI transferred the
beneficial interest in 100,000 of the Company's shares to Daniel
Young, with a corresponding reduction in the issuance of any new
JEP shares due to Daniel Young in exchange for his existing JEI
shares transferred to JEHL.
The purpose of this transfer was to ensure that the adjusted
total outstanding number of Jadestone Energy plc shares of
463,649,477 at the completion of the internal reorganisation was
exactly equal to the number of outstanding Jadestone Energy Inc.
shares of 463,649,477 immediately prior to the completion of the
reorganisation.
Compensation of key management personnel
2021 2020
USD'000 USD'000
-------- --------
Short-term benefits 7,741 6,440
Other benefits 1,295 1,006
Share-based payments 692 951
-------- --------
9,728 8,397
======== ========
The total remuneration of key management members in 2021
(including salaries and benefits) was US$9.7 million (2020: US$8.4
million) and recognised as part of the Group's administrative staff
costs as disclosed in Note 8.
Compensation of Directors
Short-term Other Share-based Total compensation
benefits(a) benefits(a) payments
USD'000 USD'000 USD'000 USD'000
2021
A. Paul Blakeley 1,367 148 302 1,817
Daniel Young 748 210 (75) 883
Dennis McShane 155 - 10 165
Iain McLaren 105 - 7 112
Robert Lambert 95 - 7 102
Cedric Fontenit 95 - 7 102
Lisa Stewart 90 - 13 103
David Neuhauser 80 - 7 87
2,735 358 278 3,371
2020
A. Paul Blakeley 1,372 100 282 1,754
Daniel Young 696 190 138 1,024
Dennis McShane 119 - 18 137
Iain McLaren 79 - 11 90
Robert Lambert 70 - 11 81
Cedric Fontenit 66 - 10 76
Lisa Stewart 74 - 12 86
David Neuhauser 57 - 11 68
2,533 290 493 3,316
(a) S hort-term benefits comprise salary, director fee as
applicable, performance pay, pension and other allowances. Other
benefits comprise benefits-in-kind.
GLOSSARY
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
2C best estimate contingent resource, 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
AAKBNLP Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields
AIM Alternative Investment Market
API American Petroleum Institute gravity
bbl barrel
bbls/d barrels per day
boe barrels of oil equivalent
boe/d barrels of oil equivalent per day
DD&A depletion, depreciation and amortisation
EBITDAX earnings before interest tax, depreciation, amortisation
and exploration
FPSO floating production storage and offloading
FSO floating storage and offloading
GB pence, Great Britain pence
GBp
GHG greenhouse gases
IFRS International Financial Reporting Standards
LPG Liquefied petroleum gas
mcf thousand cubic feet of natural gas
mm million
mmbbls million barrels
mmboe million barrels of oil equivalent
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
TCFD Task Force on Climate-Related Financial Disclosures
US$ or USD United States dollar
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FR DZGGVGKDGZZZ
(END) Dow Jones Newswires
June 06, 2022 02:02 ET (06:02 GMT)
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