TIDMJSE
RNS Number : 2436L
Jadestone Energy PLC
09 September 2021
2021 Half Year Results and Interim Dividend Declaration
9 September 2021-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 unaudited condensed
consolidated interim financial statements, as at and for the
six-month period ended 30 June 2021 (the "Financial
Statements").
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:
" I am pleased to report a solid 2021 first half across the
business, with production from our Australian assets slightly
better than expected, ahead of implementing the activity plan on
Montara and Stag that was deferred from last year due to low oil
prices. I am also pleased to report safe operational performance
through the year to date, while we remain vigilant on the
well-being of our workforce given the continued significant impact
of the COVID-19 pandemic.
"During the period, global demand for hydrocarbons has been
recovering, creating strong market fundamentals including an
increase in benchmark oil prices. Jadestone's average oil price
realisations in the first half were 45% higher than the same period
last year. This translated into positive operating cash flows of
US$54.4 million in H1 2021. Adding the proceeds of a June Montara
lifting which were received in early July, pro-forma cash balances
at mid-year were just short of US$100 million.
"With no debt, our financial position at the end of the first
half was very strong, allowing us to increase the interim dividend
by 10%. Going forward, we will continue to balance dividend growth
against the significant organic and inorganic growth opportunities,
and associated capital needs, across the business.
"I am particularly pleased with the Peninsular Malaysia
acquisition announced during H1 2021. Due to the concerted efforts
of our team, we closed the transaction just three months after
announcing, with net cash due to Jadestone of US$9.2 million.
Further, we remain committed to our acquisition of a 69% operated
interest in the Maari project, shallow water offshore New Zealand,
and remain confident that the transaction will be completed, though
timing of government approvals is beyond our control.
"Our gas developments have also seen positive progress during
the first half. At Lemang, in Indonesia, the regulator has
allocated future gas sales from the project, which provides
certainty as we work toward both formalising gas sales contracts
and progressing the various workstreams leading toward a final
investment decision. In Vietnam, we have re-engaged with regulators
to press toward a target for both the production profile and first
gas date, as a key precursor to establishing gas sales agreement
details.
"Today, we have reaffirmed production guidance for 2021 of
11,500 - 13,500 boe/d, key to which is the contribution of the H6
development well on Montara, which is currently in the completions
phase before being tied in and brought onstream shortly. This well,
together with the Skua workovers and the contribution of the
Peninsular Malaysia assets, would give us clear line of sight on a
production rate of 20,000 boe/d towards the end of the year."
Paul Blakeley
EXECUTIVE DIRECTOR,
PRESIDENT AND CHIEF EXECUTIVE OFFICER
2021 FIRST HALF RESULTS SUMMARY
USD'000 except where indicated H1 2021 H1 2020 FY 2020
-------------------------------------------- -------- -------- ------------
Production, bbls/day 9,934 12,116 11,438
Realised oil price per barrel (US$/bbl)(1) 67.70 46.47 44.79
Revenue(2) 138,158 115,669 217,938
Operating costs per barrel (US$/bbl)(3) 28.16 23.27 23.10
Adjusted EBITDAX(3) 65,179 36,606 62,582
Profit/(Loss) after tax 2,495 5,360 (60,178)(4)
Earnings/(Loss) per ordinary share:
basic & diluted (US$) 0.01 0.01 (0.13)
Dividend per ordinary share (US
) 0.59 0.54 1.62
Operating cash flows before movement
in working capital 54,376 57,054 86,883
Capital expenditure 16,221 19,521 24,065
Outstanding debt(3) - 25,574 7,386
Net cash(3) 48,291 78,281 82,055
Financial
l H1 2021 production of 9,934 bbls/d, slightly ahead of plan but
18% lower than H1 2020, in part due to natural field production
decline, deferred workovers and an unplanned shutdown at Montara
for critical valve repairs;
l Average realised oil prices(1) in H1 2021 were US$67.70/bbl,
46% higher than H1 2020. Realised prices included an average
premium over the benchmark of US$3.12/bbl(5) (H1 2020:
US$8.19/bbl);
l Net revenue for H1 2021 of US$138.2 million, up 50% from H1
2020 before hedging income(2) , due to the increase in oil prices
since the beginning of 2021 and higher lifted volumes;
l Unit operating costs(6) of US$28.16/bbl, up 21% from H1 2020
of US$23.27/bbl, in part due to lower production, coupled with
higher operational staff costs and repair & maintenance
costs;
l Net profit after tax of US$2.5 million, down from US$5.4
million in H1 2020, which includes the impact of several one-off
expenses of US$3.4 million arising from costs associated with the
acquisition of SapuraOMV Upstream (PM) Inc. as well as other
business development costs and costs associated with the corporate
reorganisation , and a net hedging loss of US$4.6 million;
l H1 2021 positive operating cash flows of US$54.4 million,
before movements in working capital, down 5% compared to H1 2020
;
l Capital expenditure of US$16.2 million, down 17% compared to
the prior period. Capital expenditure incurred in H1 2021 is
primarily related to costs of the drilling of the H6 development
well at Montara. H1 2020 development spend was primarily on the Nam
Du/U Minh field prior to the project activity being deferred during
the early stages of the COVID-19 pandemic;
l The 2018 reserves based loan was fully repaid on 31 March
2021, leaving the Group now entirely free of any interest bearing
financial indebtedness;
l Net cash as at 30 June 2021 of US$48.3 million (H1 2020:
US$78.3 million) and zero outstanding debt (H1 2020: US$ 25.6
million). The lower gross cash balance is partly due to timing
differences in liftings, with proceeds of US$46.1 million from a
Montara June 2021 lifting received in July 2021; and
l A 2021 interim dividend of 0.59 US cents/share has been declared.
(1) Realised oil price represents the actual selling price and
before any impact from hedging. The H1 2020 realised price is net
of marketing fees of US$0.08/bbl, whereas full year 2020 and H1
2021 realised oil prices are before marketing fees which are
recorded in production costs pursuant to IFRS 15 Revenue from
Contracts with Customers.
(2) Revenue in H1 2020 and FY 2020 includes hedging income of
US$23.7 million and US$31.4 million, respectively, pursuant to the
characterisation of the two-year capped swap programme as cashflow
hedges under IFRS9 Financial Instruments. Losses realised on the H1
2021 swaps of US$4.6 million have been recognised in other
expenses, pursuant to the characterisation of the ad hoc H1 2021
six-month swap programme as derivative instruments measured at fair
value through profit or loss. The H1 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 bbl, adjusted EBITDAX, outstanding debt
and net cash are non-IFRS measures and are explained below.
(4) Loss after tax for the year ended 31 December 2020 included
an impairment of US$50.5 million associated with the capitalised
intangible exploration costs at SC56.
(5) With the change to the shuttle tanker model at Stag, the
premium negotiated for each Stag lifting is now typically based on
a CIF (cost, insurance and freight) basis rather than a FOB (free
on board) basis. Care needs to be taken in making comparisons with
2020 premia for the period up until September 2020 when the switch
to the tanker model occurred.
(6) Unit operating costs per barrel before workovers, but
including net lease payments and certain other adjustments (see
non-IFRS measures below).
Business development
l Announced the acquisition of SapuraOMV's interests in
Peninsular Malaysia for an initial headline cash consideration of
US$9.0 million, plus customary adjustments and certain subsequent
contingent payments. The acquisition was completed on 1 August
2021, resulting in a net cash receipt of US$9.2 million after
adjustments; and
l Both Jadestone and the Maari seller continue to work to
satisfy the remaining outstanding conditions to complete the Maari
acquisition .
Guidance
l Full year guidance unchanged from 18 August 2021 update:
o Production : 11,500 - 13,500 boe/d;
o Unit opex: US$25.50 - 29.50/boe; and
o Capex: US$105 - 115 million.
Enquiries
Jadestone Energy plc +65 6324 0359 (Singapore)
Paul Blakeley, President and CEO
Dan Young, CFO + 44 7713 687 467 (UK)
Phil Corbett, Investor Relations Manager 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 / James Crothers jadestone@camarco.co.uk
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, Thursday, 9
September 2021, including a question-and-answer session.
The live webcast of the presentation will be available at the
below webcast link. Dial-in details are provided below. Please
register approximately 15 minutes prior to the start of the
call.
The results for the financial period ended 30 June 2021 will be
available on the Company's website at:
www.jadestone-energy.com/investor-relations/
Webcast link:
https://produceredition.webcasts.com/starthere.jsp?ei=1485258&tp_key=efaeb2a81e
Event conference title: Jadestone Energy plc - Half Year
Results
Start time: 9:00 a.m. (London)/4:00 p.m. (Singapore)
Date: Thursday, 9 September 2021
Conference ID: 24719928
Dial-in number details:
Country Dial-In Numbers
United Kingdom 08006522435
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Australia 1800076068
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Canada (Toronto) 416-764-8688
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Canada (Toll free) 888-390-0546
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New Zealand 0800453421
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Singapore 8001013217
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United States (Toll free) 888-390-0546
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France 0800916834
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Germany 08007240293
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Germany (Mobile) 08007240293
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Hong Kong 800962712
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Indonesia 0078030208221
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Ireland 1800939111
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Ireland (Mobile) 1800939111
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Japan 006633812569
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Malaysia 1800817426
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Switzerland 0800312635
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Switzerland (Mobile) 0800312635
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DIVID DECLARATION
On 9 September 2021, the directors have declared a 2021 interim
dividend of 0.59 US cents/share (or equivalent to 0.43 GB
pence/share based on the current spot exchange rate of 0.7257 ),
equivalent to a total distribution of US$ 2.8 million. 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 September 2021
l Record date: 17 September 2021
l Payment date: 1 October 2021
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.
ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG")
As a leading oil and gas development and production company in
the Asia Pacific region, Jadestone strives to deliver sustainable
value for all of its stakeholders in a safe, secure,
environmentally and socially responsible manner. Jadestone
published its second Sustainability Report in June this year, which
covered the Group's approach to ESG and performance across key
focus areas for the 2020 calendar year, as well as commitments to
further improvements in 2021.
ESG Performance
Through H1 2021, the Group maintained safe operations and had no
significant recordable personnel or environmental incidents, and no
disruptions to offshore operations due to the COVID-19 pandemic.
Jadestone has committed to 2021 ESG targets across all of its
material matters, which form a part of annual executive key
performance indicators, translating directly to performance
pay.
Jadestone has continued its focus on reducing the carbon
footprint of its operations, through the work of the Operational
and Executive subgroups of the Climate Change Working Group
("CCWG"). In 2021, the Company is targeting a 5% reduction in both
flared volumes and diesel use compared to 2020 levels.
Initiatives to reduce GHG emissions in 2021 include:
l continuing to increase the uptime of the reinjection
compressor at the Montara asset;
l prioritising usage of produced gas over diesel to run Montara
operations; and
l enhancing internal GHG emissions reporting to support improved
operational practices.
The Operational CCWG is currently reviewing the recently
acquired Peninsular Malaysia assets to identify sources of
emissions, opportunities to reduce emissions, as well as
integrating asset-level GHG reporting.
The Company has also been rolling out its community engagement
programmes in all countries of operations, to further enhance its
positive contribution to the local communities. Throughout 2021,
the focus in the regions has been on identifying most pressing
community needs and looking for optimal channels of delivery, that
prioritise employee safety. Jadestone has also continued its
employee-facing programmes, including running the Plastic Free July
campaign, where feasible.
UN Sustainable Development Goals
Jadestone's ESG framework continues to align with the wider
societal challenges addressed by the UN's Sustainable Development
Goals ("SDGs"). Whilst its business activities touch directly or
indirectly on many of the SDGs, Jadestone has selected the goals
that most closely align with its current business strategy,
activities, values and purpose. These are set out in the Company's
Sustainability Report, contained within the 2020 Annual Report.
Task Force on Climate-Related Financial Disclosures
In 2020, Jadestone commenced its alignment with the Task Force
on Climate-Related Financial Disclosures ("TCFD"), utilising it as
a practical tool for navigating the transition to a low-carbon
economy and increasing business resiliency.
In H1 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.
Jadestone will disclose its progress in TCFD adoption in its 2021
Sustainability Report, to be published in H1 2022.
Governance
The Group adopted the Quoted Companies Alliance corporate
governance code ("QCA code") at the end of 2020. The resultant
changes that arise from the adoption of the QCA code have been
implemented and are a testament to the Company's commitment to
further strengthening transparent and effective corporate
governance practices.
Further details and enhanced disclosures of ESG can be found in
the Company's 2020 Sustainability Report, as part of the 2020
Annual Report, from pages 36 to 81.
OPERATIONAL REVIEW
Producing assets
Australia
Montara project
The Montara assets, in production licences AC/L7 and AC/L8, are
located 254km offshore Western Australia, in a water depth of
approximately 77 metres. The Montara assets, comprising the three
separate fields being Montara, Skua and Swift/Swallow, are produced
through an owned FPSO, the Montara Venture. As at 31 December 2020,
the Montara assets had proven plus probable reserves of 23.4mm
barrels of oil, 100% net to Jadestone.
The fields produce light sweet crude ( 42(o) API, 0.067% mass
sulphur), which typically sells at a premium to Dated Brent. The
premium in H1 2021 ranged between US$0.39/bbl to US$0.66/bbl. The
most recent lifting was agreed at a premium of US$1.17/bbl.
During H1 2021, there was an unplanned shutdown to replace a
significant number of critical valves on the FPSO. The shutdown was
for 16 days resulting in around 102,000 bbls of deferred
production. The original valves were installed during the FPSO's
construction and the replacements should last for the remaining
life of the field.
The Montara assets produced an average of 7,269 bbls/d in the
first half of 2021 (H1 2020: 9,440 bbls/d). This was lower than H1
2020 in part due to natural field production decline and the
unplanned shutdown to replace the defective critical valves.
The Group took the Valaris 107 drilling rig on hire on 14 June
2021 and commenced drilling the H6 development well on 28 June
2021. During the initial attempt to drill the horizontal section in
the well, mechanical issues with downhole equipment resulted in a
deviation from the planned well path, which necessitated a
sidetrack. The sidetrack was successful, resulting in a circa 1,200
metre horizontal section in the reservoir, encountering good
quality oil-bearing sands. The well is currently in the completions
phase before being tied in to the Montara infrastructure, after
which the rig will proceed with the Skua 11 and 10 workovers.
There were three liftings during H1 2021, resulting in total
sales of 1,536,307 bbls, compared to 1,461,096 bbls in H1 2020 from
the same number of liftings.
Stag oilfield
The Stag oilfield, in block WA-15-L, is located 60km offshore
Western Australia, in a water depth of approximately 47 metres. As
at 31 December 2020, the field contained total proved plus probable
reserves of 13.7mm 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(1) . The most recent lifting was agreed at a premium
of US$10.15/bbl.
During H1 2021, the Group continued its workover and maintenance
programme. As a result of COVID-19 constraints, production
continues to be impacted by a backlog of workovers that are
scheduled to be complete by the end of 2021.
Production was 2,665 bbls/d during H1 2021, compared to 2,676
bbls/d in H1 2020.
There were two liftings during H1 2021, generating total sales
of 504,485 bbls, compared to 518,193 bbls in H1 2020 from the same
number of liftings.
Malaysia
PM 323 and PM 329 PSCs (operated), PM 318 and AAKBNLP PSCs
(non-operated)
On 30 April 2021, the Group announced the execution of a sale
and purchase agreement ("SPA") with SapuraOMV Upstream Sdn. Bhd.
("SapuraOMV") to acquire SapuraOMV's Peninsular Malaysia assets
(the "PenMal Assets"), for an initial cash consideration of US$9.0
million, plus customary adjustments. Further contingent payments of
up to US$6.0 million are payable to SapuraOMV, which are tied to
potential full year oil price outcomes in 2021 and 2022(2) .
The acquisition completed on 1 August 2021, following the
satisfaction of all conditions precedent, resulting in a total
final cash consideration of US$20.0 million, comprising the
headline cash consideration 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 all net cash
generated since 1 January 2021 up to the completion date. As a
result, at completion the Group obtained cash held by SapuraOMV
Upsteam (PM) Inc. of US$29.2 million, resulting in a net cash
receipt of US$9.2 million from the acquisition.
The PenMal Assets consist of four licences, two of which are
operated by the Group. The two operated licences comprise 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. Both PSCs are
located approximately 230km northeast of Terengganu. 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 PenMal Assets add immediate cash flow from around 6,000
barrels of oil equivalent per day of low operating cost production,
on a net working interest basis, of which over 90% is oil. The
Group's Malaysian operated assets produce a very light sweet crude
that is blended to Tapis grade (43 API, 0.04% mass sulphur). The
PenMal Assets also increase the Group's 2P reserves by 34%, adding
12.5mm boe, representing the net working interest 2P reserves as at
31 December 2020, based on Jadestone's best estimate 2P reserves
production profile.
(1) With the change to the shuttle tanker model at Stag, the
premium negotiated for each Stag lifting is now typically based on
a CIF basis rather than a FOB basis. Care needs to be taken in
making comparisons with 2020 premia for the period up until
September 2020 when the switch to the tanker model occurred.
(2) If the average daily price of Dated Brent crude oil in
calendar 2021 (calendar 2022) exceeds US$65/bbl (US$70/bbl), then
Jadestone pays SapuraOMV an additional US$3.0 million (US$3.0
million).
The Group believes there is scope to add incremental value in
the near term through both reservoir optimisation and production
enhancement activities across both operated licences. Gas
re-injection is expected to be a key part of reservoir
optimisation, while production enhancement will initially be
focused on restoring idle wells to production.
There is also significant potential for further development
activity on the PenMal Assets. The focus will initially be on
infill drilling in the East Belumut field within the PM 323 PSC,
where the Group sees the potential for several infill campaigns
over the next few years. East Belumut has a medium heavy oil, which
is similar to the Stag field offshore Australia, where we have
experience of increasing recovery factors through tightening of the
well pattern. There are also some targeted opportunities on the
East Piatu and West Belumut fields, which will be evaluated in
parallel with the East Belumut infill potential.
In H1 2021, average production from the PenMal assets was 12,560
boe/d, equivalent to 7,492 boe/d, net to Jadestone's working
interest. The net average realised prices incorporated into the
liftings was US$ 65.90 /bbl.
Pending acquisition
New Zealand
Maari oilfield
On 16 November 2019, the Group executed an SPA with OMV New
Zealand Limited ("OMV New Zealand"), to acquire an operated 69%
interest in the Maari project, located 120km 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, including extending the long stop date under
the SPA from 31 August 2021 to 31 December 2021, as announced on 8
September 2021.
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 now anticipated to be a net receipt to
the Group.
As at 31 December 2020, the Maari project holds net 2P audited
reserves of 10.6mm barrels of oil.
Pre-production assets
Vietnam
Block 51 PSC and Block 46/07 PSC
Jadestone holds a 100% operated working interest in Block 46/07
PSC and Block 51 PSC, 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 93.9mm boe.
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 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.
Indonesia
Lemang PSC
The Lemang PSC is located onshore Sumatra, Indonesia. The block
includes the Akatara gas field, with a net to Jadestone 2C resource
of 16.8mm boe.
The asset has been substantially de-risked with 11 wells drilled
into the structure, plus three years of oil production history, up
until the field ceased production of oil in December 2019.
On 30 June 2021, the Minister of Mines and Energy of Indonesia
issued a Ministerial decree, allocating gas sales from the Akatara
gas field in the Lemang PSC to a subsidiary of the national
electricity utility, PT Perusahaan Listrik Negara ("PLN").
The Ministerial decree facilitates the development and
commercialisation of the Akatara gas field and also the associated
production and sales of liquefied petroleum gas to the local
domestic market in Jambi, together with condensate sales to a local
buyer.
A heads of agreement ("HoA") in relation to gas sales from
Jadestone's planned development has also been executed with the PLN
subsidiary, PT Pelayanan Listrik Nasional Batam ("PLN Batam"), as
buyer. A fully termed gas sales agreement is currently under
negotiation with PLN Batam.
The Ministerial decree and HoA specify a gross sales volume of
20 BBtu/d starting in Q1 2024, and a plant gate sales price of
US$5.60/mmBtu, at a delivery point approximately 17 kilometres from
the field.
Indonesia's upstream regulator, SKK Migas, has approved the HoA
which is fully aligned with the Ministerial decree.
Exploration assets
Philippines
Service Contract 56 ("SC56")
Jadestone held a 25% interest in SC56 in partnership with
operator Total E&P Philippines B.V. ("Total").
On 18 November 2020, Total and Jadestone expressed their
intention to the Philippines Department of Energy ("DOE") to
voluntarily surrender the entire interest in SC56 and accordingly,
to terminate the contract. The effective date of termination was 21
December 2020.
Following the termination, the Group is liable for 25% of the
unfulfilled minimum work programme as at the termination date. At
the end of June 2021, the Group received the finalised unfulfilled
commitment amount from the DOE and is required to pay US$1.5
million, net 25% to Jadestone. The payment of this unfulfilled
commitment amount will be funded from the net arbitration proceeds
of US$2.2 million received from Total in 2020.
Service Contract 57 ("SC57")
The Group holds a 21% working interest in SC57, but it has been
under force majeure since 2011, and these conditions are expected
to continue for the foreseeable future.
FINANCIAL REVIEW
The following table provides selected financial information of
the Group, which was derived from, and should be read in
conjunction with, the unaudited condensed consolidated interim
financial statements for the period ended 30 June 2021.
Twelve
Six months Six months months
ended ended ended
30 June 30 June 31 December
USD'000 except where indicated 2021 2020 2020
-------------------------------------------- ----------- ----------- -------------
Sales volume, barrels (bbls) 2,040,792 1,979,289 4,165,612
Production, bbls/day 9,934 12,116 11,438
Realised oil price per barrel (US$/bbl)(1) 67.70 46.47 44.79
Revenue(2) 138,158 115,669 217,938
Production costs (62,492) (44,466) (105,338)
Operating costs per barrel (US$/bbl)(3) 28.16 23.27 23.10
Adjusted EBITDAX(3) 65,179 36,606 62,582
Unit depletion, depreciation &
amortisation (US$/bbl) 15.70 16.14 16.24
Impairment - - 50,455
Profit/(Loss) before tax 11,148 12,787 (57,238)
Profit/(Loss) after tax 2,495 5,360 (60,178)
Earnings/(Loss) per ordinary share:
basic & diluted (US$) 0.01 0.01 (0.13)
Dividend per ordinary share (US
) 0.59 0.54 1.62
Operating cash flows before movement
in working capital 54,376 57,054 86,883
Capital expenditure 16,221 19,521 24,065
Outstanding debt(3) - 25,574 7,386
Net cash(3) 48,291 78,281 82,055
Benchmark commodity price and realised price
The average benchmark Dated Brent crude oil price increased 62%
to US$64.98/bbl in the first half of 2021, compared to US$40.07/bbl
in H1 2020. The average benchmark Dated Brent oil price
incorporated into the Group's liftings was US$64.58/bbl in H1 2021,
a 68% increase compared to US$38.36/bbl in H1 2020.
(1) Realised oil price represents the actual selling price and
before any impact from hedging. The H1 2020 realised price is net
of marketing fees of US$0.08/bbl, whereas full year 2020 and H1
2021 realised oil prices are before marketing fees which are
recorded in production costs pursuant to IFRS 15 Revenue from
Contracts with Customers . With the change to the shuttle tanker
model at Stag, the premium negotiated for each Stag lifting is now
typically based on a CIF basis rather than a FOB basis. Care needs
to be taken in making comparisons with 2020 premia for the period
up until September 2020 when the switch to the tanker model
occurred.
(2) Revenue in H1 2020 and FY 2020 includes hedging income of
US$23.7 million and US$31.4 million, respectively, pursuant to the
characterisation of the two-year capped swap programme as cashflow
hedges under IFRS9 Financial Instruments. Losses realised on the H1
2021 swaps of US$4.6 million have been recognised in other
expenses, pursuant to the characterisation of the ad hoc H1 2021
six-month swap programme as derivative instruments measured at fair
value through profit or loss. The H1 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) Net cash at June 2021 excludes a Montara June lifting of
US$46.1 million, the proceeds of which were received in July 2021
(by comparison, there were no Montara or Stag liftings in December
2020 or June 2020). Operating costs per bbl, adjusted EBITDAX,
outstanding debt and net cash are non-IFRS measures and are
explained below.
The actual average realised price in H1 2021 increased by 4 6 %
to US$67.70/bbl, compared to US$46.47/bbl in H1 2020. The average
premium during the period was US$3.12/bbl, compared to US$8.19/bbl
in H1 2020. Premiums continue to improve with the latest liftings
achieving US$10.15/bbl and US$ 1.17/bbl at Stag and Montara,
respectively. With the change to the shuttle tanker model at Stag,
the premium negotiated for each Stag lifting is now typically based
on a CIF basis rather than a FOB basis. Care needs to be taken in
making comparisons with 2020 premia for the period up until
September 2020 when the switch to the tanker model occurred.
Production and liftings
The Group generated average production in H1 2021 of 9,934
bbls/d (H1 2020: 12,116 bbls/d). Production at Montara was lower
compared to H1 2020, primarily the result of natural field
production decline and an unplanned shutdown at Montara for 16 days
resulting in around 102,000 bbls of deferred production.
The Group had five liftings during the period, resulting in
sales of 2,040,792 bbls (H1 2020: 1,979,289 bbls, five
liftings).
Revenue
The Group generated US$138.2 million of revenue in H1 2021,
compared to US$115.7 million for the same period in 2020, an
increase of 19%. The increase in revenue was predominately due
to:
-- Higher average realised prices in H1 2021, compared to H1
2020 (US$67.70/bbl vs US$46.47/bbl), contributing an additional
US$41.8 million;
-- A 3% increase in lifted volumes in H1 2021, compared to H1
2020, generating additional revenue of US$4.2 million; and
-- Hedging income was nil(1) in H1 2021, a decline of US$23.7
million compared to H1 2020. The Group's two-year capped swap
cashflow hedge programme ran through to 30 September 2020.
Production costs
Production costs in H1 2021 were US$62.5 million (H1 2020:
US$44.5 million), an increase of US$18.0 million compared to H1
2020, predominately due to:
-- An additional US$8.8 million of net movement in closing crude
inventories of 448kbbls, due to liftings exceeding production
between the comparable periods;
-- Operational staff costs were higher by US$2.0 million, due to
additional contractors recruited to support repair and maintenance
activities and unfavorable foreign exchange movements in non-US$
salaries;
-- Repair and maintenance ("R&M") costs increased by US$2.2
million compared to H1 2020, due to additional spending on
fabrication and inspection activities on both Stag and Montara;
-- Workover costs were higher by US$4.4 million, due to limited
activity in 2020 in response to COVID-19 impacts on oil prices and
restrictions in crew movements. The Group resumed its workover
campaigns at Stag during H2 2020, with more workovers and well
interventions activities in the first half of 2021 compared to H1
2020; and
-- Transportation costs of US$0.5 million (H1 2020: nil)
following the change in offtake arrangements at Stag.
The termination of the Dampier Spirit FSO lease resulted in
estimated cash savings of US$3.7 million during H1 2021.
(1) The hedging loss in H1 2021 of US$4.6 million was recognised
as other expenses, as opposed to offsetting against revenue, due to
the adoption of a different accounting treatment for the H1 2021
commodity swap contracts. The two-year capped swap programme was
characterised as cashflow hedges under IFRS9 Financial Instruments
and realised gains recognised as part of revenue. Losses realised
on the H1 2021 swaps have been recognised in other expenses,
pursuant to the characterisation of the ad hoc H1 2021 six-month
swap programme as derivative instruments measured at fair value
through profit or loss. The H1 2021 programme covered a short time
span (not exceeding a half yearly reporting period), whereas the
capped swap programme crossed three annual reporting periods.
Unit operating costs per barrel were US$28.16 (H1 2020:
US$23.27/bbl) before workovers, an increase on H1 2020,
predominately due to lower production as a result of natural field
decline production, coupled with higher operational staff costs and
R&M costs as explained above.
DD&A, other operating expenses and income
DD&A charges in H1 2021 were US$39.7 million, versus H1 2020
of US$39.2 million, reflecting the slightly higher lifted volumes.
The DD&A on a unit basis for oil and gas properties remained
consistent with prior periods, while depreciation for right-of-use
assets reduced primarily as a result of the September 2020
termination of the Dampier Spirit leased FSO at Stag.
Other expenses in H1 2021 were US$12.5 million (H1 2020: US$16.6
million), including the fair value loss on commodity swaps of
US$4.6 million, and several one-off expenses including costs
associated with the acquisition of SapuraOMV's interests in
Peninsular Malaysia of US$0.8 million, business development related
expenses of US$1.3 million, COVID-19 related expenses of US$0.7
million, and costs associated with the corporate reorganisation of
US$ 1.1 million . In comparison, other expenses in H1 2020 mainly
comprised litigation expenses of US$8.8 million in relation to the
SC56 arbitration with Total, rig contract deferral costs in
Australia of US$3.0 million, and seismic acquisition costs incurred
at Montara of US$1.0 million.
H1 2021 other income totalled US$3.7 million (H1 2020: US$15.4
million), arising from rebate income of US$2.7 million, generated
from the sublease of right-of-use assets under the Group's
helicopter lease contract, and foreign exchange gains of US$1.0
million. In comparison, other income in H1 2020 included US$11.1
million awarded to the Group, for the breach of the SC56 farm out
agreement by Total, and fair value gain on capped swaps of US$2.1
million.
Taxation
The overall net tax expense of US$8.7 million (H1 2020: US$7.4
million) comprises current income tax expense of US$8.9 million (H1
2020: US$10.5 million), reduced by a deferred tax credit of US$0.2
million (H1 2020: US$3.1 million).
Current income tax expense of US$8.9 million (H1 2020: US$10.5
million) consists of corporate income tax of US$11.4 million,
offset by a PRRT tax credit of US$2.5 million, with a PRRT refund
received in August, as annual deductible cash payments exceeded
assessable cash receipts.
The deferred tax credit of US$0.2 million (H1 2020: US$3.1
million) has arisen from timing differences between the tax and
accounting treatment of depreciation for oil and gas
properties.
H1 2021 RECONCILIATION OF CASH
USD'000 USD'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 138,158
Other operating income 2,908
Operating costs (62,492)
Staff costs (11,427)
General and administrative expenses (12,771)
Cash flows from operations 54,376
Movement in working capital (53,254)(1)
Tax paid (8,004)
Interest paid (768)
Purchases of intangible exploration assets,
oil and gas properties, and
plant and equipment(2) (15,865)
Other investing activities 38
Financing activities (17,673)
------------
Total cash and cash equivalent, 30 June
2021 48,291(1)
============
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 (opex/bbl), adjusted EBITDAX, outstanding debt, and
net cash.
The following notes describe why the Group has selected these
non-IFRS measures.
(1) Total cash does not include a June lifting at Montara for
US$46.1 million, the proceeds of which were received in July 2021.
There were no December 2020 liftings/no outstanding trade
receivable from a lifting at the December 2020 year end. The
receivable from the June lifting is reflected in trade receivables
as at 30 June 2021.
(2) Total capital expenditure was US$16.2 million, comprising
total capital expenditure paid of US$15.9 million, plus accrued
capital expenditure of US$0.3 million.
Operating costs per barrel (Opex/bbl)
Opex/bbl 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/bbl is defined as total production costs excluding
oil inventories movement, write down of inventories, workovers (to
facilitate better comparability period to period) and non-recurring
repair and maintenance. It also includes lease payments related to
operational activities, net of any income earned from right-of-use
assets involved in production, and foreign exchange gains arising
from foreign exchange forwards in respect of local currency
operating expenditure, and excludes depletion, depreciation and
amortisation and short term COVID-19 subsidies. Adjusted aggregate
production cost is then divided by total produced barrels for the
prevailing period, to determine the unit cost per barrel.
Six months Six months Twelve months
ended ended ended
30 June 30 June 31 December
USD'000 except where indicated 2021 2020 2020
---------------------------------------- ----------- ----------- -------------
Production costs (reported) 62,492 44,466 105,338
Adjustments
Lease payments related to
operating activities(1) 6,444 10,005 17,548
Movement in oil inventories(2) (5,642) 3,204 2,806
Workover costs(3) (10,027) (5,675) (21,686)
Write down of oil inventories(4) - (695) -
Impact from foreign exchange
derivatives
apportioned to production
costs(5) - - (2,649)
Other income(6) (2,286) - (3,634)
Non-recurring repair and maintenance(7) - - (1,619)
Transportation costs (541) - -
Australian Government JobKeeper
scheme 196 - 600
Adjusted production costs 50,636 51,305 96,704
----------- ----------- -------------
Total production, barrels 1,797,989 2,205,042 4,186,478
Operating costs per barrel 28.16 23.27 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 the lease termination in September
2020. The lease payments are added back to reflect the true cost of
production.
(2) Movement in oil inventories are added back to the
calculation to match the full cost of production with the
associated production volumes.
(3) Workover costs are excluded from opex/bbl so as to enhance
comparability. The frequency of workovers can vary significantly,
across reporting periods, particularly at Stag.
(4) Write down of oil inventories in H1 2020 is a non-cash
adjustment based on the requirements of IAS 2 Inventories to
reflect the closing inventories being recorded at the lower of cost
or net realisable value. It is not considered a production
cost.
(5) A portion of the net impact from foreign exchange hedging
instruments in 2020 was apportioned to production costs, based on
the Group's actual local currency expenditure during the hedging
period.
(6) Other income represents the rental income from a helicopter
rental contract (a right-of-use asset) to a third party.
(7) Non-recurring repair and maintenance costs in 2020 relates
to costs associated with Cyclone Damien.
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 and exploration.
The calculations of adjusted EBITDAX are as follow:
Six months Six months Twelve months
ended ended ended
30 June 30 June 31 December
USD'000 2021 2020 2020
Revenue 138,158 115,669 217,938
Production costs (62,492) (44,466) (105,338)
Staff costs (12,067) (11,425) (21,903)
Impairment of assets - - (50,455)
Other expenses (12,501) (16,642) (26,918)
Other income, excluding interest
income 3,643 11,075 26,119
Other financial gains - 359 359
----------- ----------- --------------
Unadjusted EBITDAX 54,741 54,570 39,802
Non-recurring
Net loss/(gain) from oil
price derivatives 4,633 (23,695) (30,889)
Impairment of assets - - 50,455
Non-recurring opex(1) 1,574 3,311 8,270
Net litigation income - (2,295) (3,005)
Rig contract deferred costs - 3,000 3,000
Gain on contingent consideration - (359) (359)
Gain from termination of
FSO lease - - (6,429)
Others(2) 4,231 2,074 1,737
----------- ----------- --------------
10,438 (17,964) 22,780
----------- ----------- --------------
Adjusted EBITDAX 65,179 36,606 62,582
=========== =========== ==============
(1) Includes one-off major maintenance/well intervention
activities, in particular the workover campaigns at Skua 10, Skua
11 during H1 2021 and H3 in 2020, as well as 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 corporate
re-organisation 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 30 June 2021, the Group has no outstanding interest
bearing financial indebtedness of any kind, following the final
scheduled repayment of the 2018 reserves based loan at the end of
Q1 2021.
30 June 30 June 31 December
USD'000 2021 2020 2020
----------------------------- -------- -------- -----------
Short term borrowing - 25,053 7,296
Add back: effective interest
method financing costs - 521 90
--------- -------- -----------
Outstanding debt - 25,574 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. The measure
is used to ensure capital is managed effectively in order to
support its ongoing operations, and to raise additional funds, if
required.
30 June 30 June 31 December
USD'000 2021 2020 2020
-------------------------- -------- ---------- -----------
Outstanding debt - (25,574) (7,386)
Cash and cash equivalents 47,291 95,457 80,996
Restricted cash 1,000 8,398 8,445
-------- ---------- -----------
Net cash 48,291 78,281 82,055
======== ========== ===========
Net cash is defined as the sum of cash and cash equivalents less
outstanding debt. Net cash as at 30 June 2021 excludes a Montara
June lifting of US$46.1 million, the proceeds of which were
received in July 2021 (by comparison, there were no Montara or Stag
liftings in December 2020 or June 2020). The net cash as at 30 June
2020 included the minimum working capital balance of US$15.0
million required under the Group's RBL, and restricted cash of
US$8.4 million in the RBL debt service reserve account, less
outstanding debt. The restricted cash of US$1.0 million as at 30
June 2021 represents a cash collateralised bank guarantee placed
with the Indonesian regulator with respect to a joint study
agreement entered into by the Group in Indonesia. The bank
guarantee was released in August 2021.
2021 PRINCIPAL FINANCIAL RISKS AND UNCERTAINTIES
The Group manages principal risks and uncertainties via its risk
management framework. The Group is exposed to a variety of
political, technological, environmental, operational and financial
risks which are monitored and/or mitigated to acceptable
levels.
The Group's risk management framework provides a systematic
process for the identification of the principal risks which have
the possibility of impacting the Group's strategic objectives. The
board regularly reviews the principal risks and defines corporate
targets based on acceptable levels of risk. The board assesses
material risks quarterly with a full review of the risk matrix at
least twice per year.
Details of the principal risks and uncertainties facing the
Group as at 30 June 2021 remain unchanged from the risks disclosed
in the 2020 Annual Report pages 32 to 34. The Group's risk
mitigation activities also remain unchanged.
GOING CONCERN
The directors have adopted the going concern basis in preparing
these unaudited condensed consolidated interim financial
statements, having considered the principal financial risks and
uncertainties of the Group.
The directors believe that the Group is well placed to manage
its financing and other business risks satisfactorily. The
directors have a reasonable expectation that the Group will have
adequate resources to continue in operation for at least 12 months
from the date of these unaudited condensed consolidated interim
financial statements. They therefore consider it appropriate to
adopt the going concern basis of accounting in preparing these
financial statements.
STATEMENT OF DIRECTORS' RESPONSIBILITIES
The directors confirm that to the best of their knowledge:
a. the condensed consolidated interim set of financial
statements has been prepared in accordance with IAS 34 Interim
Financial Reporting ;
b. the interim management report includes a fair review of the
information required by DTR 4.2.7R (indication of important events
during the first six months and description of principal risks and
uncertainties for the remaining six months of the year); and
c. the interim management report includes a true and fair review
of the information required by DTR 4.2.8R (disclosure of related
parties' transactions and changes therein).
By order of the Board,
Paul Blakeley Dan Young
Executive Director Executive Director
President & Chief Executive Officer Chief Financial
Officer
9 September 2021 9 September 2021
Cautionary statements
This announcement may contain certain forward-looking statements
with respect to the Company's expectations and plans, strategy,
management's objectives, future performance, production, reserves,
costs, revenues and other trend information. These statements are
made by the Company in good faith based on the information
available at the time of this announcement, but such statements
should be treated with caution due to inherent risks and
uncertainties. These statements and forecasts involve risk and
uncertainty because they relate to events and depend upon
circumstances that may occur in the future. There are a number of
factors which could cause actual results or developments to differ
materially from those expressed or implied by these forward-looking
statements and forecasts. The statements have been made with
reference to forecast price changes, economic conditions and the
current regulatory environment. Nothing in this announcement should
be construed as a profit forecast. Past share performance cannot be
relied upon as a guide to future performance. The Company does not
assume any obligation to publicly update the information, except as
may be required pursuant to applicable laws.
The oil, natural gas and natural gas liquids information in this
announcement has been prepared in accordance with National
Instrument 51-101 - Standards of Disclosure for Oil and Gas
Activities and the Canadian Oil and Gas Evaluation Handbook.
A barrel of oil equivalent ("boe") is determined by converting a
volume of natural gas to barrels using the ratio of six thousand
cubic feet ("mcf") to one barrel. Boes may be misleading,
particularly if used in isolation. A boe conversion ratio of 6
mcf:1 boe is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. Given that the value ratio based
on the current price of oil as compared to natural gas is
significantly different from the energy equivalency of 6:1,
utilising a conversion on a 6:1 basis may be misleading as an
indication of value.
The technical information contained in this announcement has
been prepared in accordance with the June 2018 guidelines endorsed
by the Society of Petroleum Engineers, World Petroleum Congress,
American Association of Petroleum Geologists and Society of
Petroleum Evaluation Engineers Petroleum Resource Management
System.
Henning Hoeyland of Jadestone Energy plc, Group Subsurface
Manager with a Masters degree in Petroleum Engineering, and who is
a member of the Society of Petroleum Engineers and has been
involved in the energy industry for more than 19 years, has read
and approved the technical disclosure in this regulatory
announcement.
The information contained within this announcement is considered
to be inside information prior to its release, as defined in
Article 7 of the Market Abuse Regulation No. 596/2014 which is part
of UK law by virtue of the European Union (Withdrawal) Act 2018,
and is disclosed in accordance with the Company's obligations under
Article 17 of those Regulations.
Condensed Consolidated Statement of Profit or Loss and Other
Comprehensive Income
for the six months ended 30 June 2021
Six months Six months Twelve months
ended ended ended 31
30 June 30 June December
2021 2020 2020
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
------------------------------------ ------ ----------- ----------- --------------
Consolidated statement
of profit or loss
Revenue 138,158 115,669 217,938
Production costs 6 (62,492) (44,466) (105,338)
Depletion, depreciation
and amortisation 6 (39,697) (39,230) (84,642)
Staff costs (12,067) (11,425) (21,903)
Other expenses 6 (12,501) (16,642) (26,918)
Impairment of assets 7 - - (50,455)
Other income 3,681 15,356 26,376
Finance costs 8 (3,934) (6,834) (12,655)
Other financial gains - 359 359
----------- ----------- --------------
Profit/(Loss) before tax 11,148 12,787 (57,238)
Income tax expense 9 (8,653) (7,427) (2,940)
----------- ----------- --------------
Profit/(Loss) for the period/year 2,495 5,360 (60,178)
=========== =========== ==============
Earnings/(Loss) per ordinary
share
Basic and diluted (US$) 10 0.01 0.01 (0.13)
=========== =========== ==============
Consolidated statement
of comprehensive
Income
Profit/(Loss) for the period/year 2,495 5,360 (60,178)
Other comprehensive income/(loss)
Items that may be reclassified
subsequently
to profit or loss:
Gain on unrealised cash
flow hedges - 26,765 26,093
Hedging gain reclassified
to profit or loss - (23,697) (31,364)
----------- ----------- --------------
- 3,068 (5,271)
Tax (expense)/credit relating
to
components of other comprehensive
income/(loss) - (921) 1,583
----------- ----------- --------------
Other comprehensive income/(loss) - 2,147 (3,688)
----------- ----------- --------------
Total comprehensive income/(loss)
for the
period/year 2,495 7,507 (63,866)
=========== =========== ==============
Condensed Consolidated Statement of Financial Position as at 30
June 2021
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
---------------------------------- ------ ---------- -------------- -----------------
Assets
Non-current assets
Intangible exploration
assets 11 96,443 135,105 100,670
Oil and gas properties 12 303,625 347,829 317,676
Plant and equipment 12 1,584 1,680 1,652
Right-of-use assets 12 18,358 51,070 23,673
Other receivables 13 4,451 - 4,404
Restricted cash - 10,000 -
Deferred tax assets 16,318 16,535 19,727
---------- -------------- -----------------
Total non-current assets 440,779 562,219 467,802
---------- -------------- -----------------
Current assets
Inventories 34,812 46,399 45,361
Trade and other receivables 13 63,135 12,637 7,110
Derivative financial instruments 19 - 10,417 -
Restricted cash 1,000 8,398 8,445
Cash and cash equivalents 47,291 95,457 80,996
---------- -------------- -----------------
Total current assets 146,238 173,308 141,912
---------- -------------- -----------------
Total assets 587,017 735,527 609,714
========== ============== =================
Equity and liabilities
Equity
Capital and reserves
Share capital 14 392 466,573 466,979
Merger reserve 15 146,269 - -
Share based payments reserve 25,625 24,492 24,985
Hedging reserve - 5,835 -
Accumulated losses (12,710) (263,291) (331,322)
---------- -------------- -----------------
Total equity 159,576 233,609 160,642
---------- -------------- -----------------
Non-current liabilities
Provisions 16 290,693 283,194 288,224
Lease liabilities 9,086 33,881 13,305
Tax liabilities - - 26,896
Deferred tax liabilities 54,564 63,155 58,229
---------- -------------- -----------------
Total non-current liabilities 354,343 380,230 386,654
---------- -------------- -----------------
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
---------------------------------- ------ ---------- -------------- -----------------
Current liabilities
Borrowings 17 - 25,053 7,296
Lease liabilities 11,625 20,420 12,478
Trade and other payables 18 22,760 22,574 32,192
Provisions 16 3,091 1,705 4,558
Derivative financial instruments 19 - - 471
Tax liabilities 35,622 51,936 5,423
---------- -------------- -----------------
Total current liabilities 73,098 121,688 62,418
---------- -------------- -----------------
Total liabilities 427,441 501,918 449,072
---------- -------------- -----------------
Total equity and liabilities 587,017 735,527 609,714
========== ============== =================
Condensed Consolidated Statement of Changes in Equity as at 30
June 2021
Share
based
Share Merger payments Hedging Accumulated
capital reserve reserve reserve losses Total
USD'000 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
Profit for
the period - - - - 5,360 5,360
Other
comprehensive
income for
the
period - - - 2,147 - 2,147
---------- --------- --------- ------------ ---------
Total
comprehensive
income for
the
period - - - 2,147 5,360 7,507
---------- -------- --------- --------- ------------ ---------
Share-based
compensation - - 635 - - 635
--------
As at 30
June 2020 466,573 - 24,492 5,835 (263,291) 233,609
========== ======== ========= ========= ============ =========
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
loss for
the year - - - (3,688) - (3,688)
---------- --------- --------- ------------ ---------
Total
comprehensive
loss for
the year - - - (3,688) (60,178) (63,866)
---------- -------- --------- --------- ------------ ---------
Dividend
paid - - - - (2,493) (2,493)
Share-based
compensation - - 1,128 - - 1,128
Shares issued,
net of
transaction
costs 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
========== ======== ========= ========= ============ =========
Share
based
Share Merger payments Hedging Accumulated
capital reserve reserve reserves losses Total
USD'000 USD'000 USD'000 USD'000 USD'000 USD'000
--------------------- ---------- -------- --------- --------- ------------ ---------
As at 1 January
2021 466,979 - 24,985 - (331,322) 160,642
Profit for
the period,
representing
total
comprehensive
income for
the
period - - - - 2,495 2,495
---------- -------- --------- --------- ------------ ---------
Dividend
paid - - - - (5,000) (5,000)
Share-based
compensation - - 640 - - 640
Shares issued,
net of transaction
costs 799 - - - - 799
Capital reduction (467,386) 146,269 - - 321,117 -
---------- -------- --------- --------- ------------ ---------
Total transactions
with owners,
recognised
directly
in equity (466,587) 146,269 640 - 316,117 (3,561)
---------- -------- --------- --------- ------------ ---------
As at 30
June 2021 392 146,269 25,625 - (12,710) 159,576
========== ======== ========= ========= ============ =========
Condensed Consolidated Statement of Cash Flows for the six
months ended 30 June 2021
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
------------------------------------ ------ ----------- ----------- -------------
Operating activities
Profit/(Loss) before tax 11,148 12,787 (57,238)
Adjustments for:
Depletion, depreciation
and amortisation 6 33,338 30,352 68,414
Depreciation of right-of-use 6 /
assets 12 6,359 8,878 16,228
Other finance costs 7 3,784 5,260 10,289
Share based payments 640 635 1,128
Provision for doubtful 201 - -
debts
Interest expense 7 150 1,574 2,366
Unrealised foreign exchange
(gain)/loss (735) - 1,495
Reversal of fair value (471) - -
loss on oil derivatives
Interest income (38) (251) (257)
Write down of inventories - 695 -
Loss on ineffective hedge
recycled to profit
or loss - 2 4
Fair value gain on foreign
exchange forward
Contracts - (2,076) -
Change in Stag FSO provision - (443) (5,047)
Decrease in fair value
of Montara contingent
Payments - (359) (359)
Impairment of intangible
exploration assets 7 - - 50,455
Fair value loss on oil
derivatives - - 471
Inventories written off - - 173
Provision of slow moving
inventories - - 143
Gain from termination of
right-of-use asset - - (1,382)
Operating cash flows before
movements in
working capital 54,376 57,054 86,883
(Increase)/Decrease in trade
and other
receivables (53,777) 29,646 35,560
Decrease/(Increase) in inventories 5,719 (10,234) (14,071)
(Decrease)/Increase in trade
and other
payables (5,196) (10,163) 3,736
----------- ----------- -------------
Cash generated from operations 1,122 66,303 112,108
Interest paid (768) (1,110) (1,542)
Tax paid (8,004) (3,260) (25,969)
----------- ----------- -------------
Net cash (used in)/generated
from operating
activities (7,650) 61,933 84,597
----------- ----------- -------------
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
Notes USD'000 USD'000 USD'000
------------------------------------ ------ ----------- ----------- -------------
Investing activities
Net cash outflows on acquisition
of Lemang
PSC - - (11,959)
Payment for oil and gas
properties 12 (14,173) (1,750) (4,732)
Payment for plant and equipment 12 (216) (106) (473)
Payment for intangible exploration
assets 11 (1,476) (11,129) (14,253)
Transfer from debt service
reserve account 7,445 5,087 5,040
Interest received 38 251 257
----------- ----------- -------------
Net cash used in investing
activities (8,382) (7,647) (26,120)
----------- ----------- -------------
Financing activities
Net proceeds from issuance
of shares 799 - 406
Release of deposit for bank
guarantee - - 10,000
Dividends paid (5,000) - (2,493)
Repayment of borrowings (7,356) (24,570) (42,766)
Repayment of lease liabilities (6,116) (10,193) (18,562)
Net cash used in financing
activities (17,673) (34,763) (53,415)
----------- ----------- -------------
Net (decrease)/increase
in cash and cash
equivalents (33,705) 19,523 5,062
Cash and cash equivalents
at beginning of the
period/year 80,996 75,934 75,934
----------- ----------- -------------
Cash and cash equivalents
at end of the
period/year 47,291 95,457 80,996
=========== =========== =============
Explanation Notes to the Condensed Consolidated Interim
Financial Statements
for the six months ended 30 June 2021
1. GENERAL INFORMATION
Jadestone Energy plc (the "Company" or "Jadestone") is an oil
and gas company incorporated in England and Wales. The Company was
incorporated on 22 January 2021, company registration number
13152520. The Company became the ultimate parent company on 23
April 2021, following the completion of a corporate reorganisation
(see below).
The Company's shares are traded on AIM under the symbol
"JSE".
The financial statements are expressed in United States
Dollars.
The Company and its subsidiaries (the "Group") are engaged in
production, development, exploration and appraisal activities in
Australia, Malaysia, Vietnam, Indonesia and the Philippines. The
Group's producing assets during H1 2021 were in the Vulcan
(Montara) and Carnarvon (Stag) basins, offshore Western
Australia.
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.
These financial statements were authorised for issue and release
by the Company's board of directors on 9 September 2021, on the
recommendation of the audit committee.
2. DIVIDS
On 11 June 2021, the directors declared a 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$7.5 million in respect of
total 2020 dividends. The dividend was paid on 30 June 2021.
On 9 September 2021, the directors declared a 2021 interim
dividend of 0.59 US cents/share (or equivalent to 0.43 GB
pence/share based on the current spot exchange rate of 0.7257 ),
equivalent to a total distribution of US$ 2.8 million. The dividend
will be paid on a gross basis, in US dollars.
3. SIGNIFICANT EVENTS DURING THE PERIOD
Corporate 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, have
been replaced on a one-for-one basis with shares of Jadestone
Energy plc. Following the completion of the internal
reorganisation, Jadestone Energy plc was admitted to AIM for
trading on 26 April 2021 (Jadestone Energy Inc. shares ceased
trading on 23 April 2021).
The internal reorganisation has not resulted in a change in
control in the ultimate holding company of the Group and,
accordingly, has not resulted in a change in control in the
ultimate shareholding in any of the companies or assets of the
Group. Further, the internal reorganisation has not resulted in a
change in the management of any of the Group's companies or
assets.
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, and subject to certain
subsequent contingent payments related to the price of average
annual Dated Brent throughout 2021 and 2022. The acquisition was
completed on 1 August 2021.
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. As a result,
at completion the Group obtained cash held by SapuraOMV Upstream
(PM) Inc. of US$29.2 million, resulting in a net cash receipt of
US$9.2 million for the acquisition.
The PenMal Assets comprise four licences, two of which are
operated by the Group. These consist of 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 consist of
50% non-operated working interests in the PM318 and 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 during the
period leading into the 2021 offshore Australia capital programme.
The average swap price, referenced to Dated Brent, was set at
US$61.40/bbl.
4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PREPARATION
These unaudited condensed consolidated interim financial
statements (the "financial statements") are prepared in accordance
with International Accounting Standard IAS 34 Interim Financial
Reporting, as adopted by the European Union, on a going concern
basis under the historical cost convention.
These unaudited condensed consolidated interim financial
statements do not comprise statutory accounts within the meaning of
section 435 of the Companies Act 2006 ("the Act"). They do not
contain all disclosures required by IFRS for annual financial
statements and should be read in conjunction with Jadestone's
audited consolidated financial statements for the year ended 31
December 2020. Jadestone's auditors reported on those accounts;
their report was unqualified and did not draw attention to any
matters by way of emphasis.
These financial statements have been prepared on an historical
cost basis, except for financial instruments classified as
financial instruments at fair value, which are stated at their fair
values, and operating leases which are stated at the present value
of future cash payments.
In addition, these financial statements have been prepared using
the accrual basis of accounting.
Common control transaction
As disclosed in Note 3, 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, Jadestone Energy plc was admitted to AIM
for trading on 26 April 2021. There is no change in control in the
ultimate holding company of the Group arising from the completion
of the internal reorganisation.
IFRS 3 Business Combinations does not prescribe the presentation
and disclosure requirements under common control transaction. The
Group has chosen to issue these unaudited condensed consolidated
interim 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 period. The following
have been reflected in these unaudited condensed consolidated
interim 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 share capital of JEI immediately before the internal
reorganisation;
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;
and
e) the comparative information presented in these consolidated
financial statements is that of JEI Group.
GOING CONCERN
The directors are satisfied that the Group has sufficient
resources to continue in operation for the foreseeable future, a
period of not less than 12 months from the date of this report.
Accordingly, they continue to adopt the going concern basis in
preparing the condensed consolidated interim financial
statements.
RECLASSIFICATION OF COMPARATIVE FIGURES
Certain comparative figures in the unaudited financial
statements of the Group for the period ended 30 June 2020 have been
reclassified to conform with the audited consolidated financial
statements for the year ended 31 December 2020, along with the
presentation in the current period.
The reclassifications made in the statement of profit or loss
are mainly related to the litigation income and expenses in
relation to SC56, which are now present on a gross basis under
other income and other expenses, respectively. These
reclassifications were made to better reflect the nature of the
respective items in the Group's financial statements.
Adoption of new and revised standards
New and amended IFRS standards that are effective for the
current period
The Group has applied the following amendment that is relevant
to the Group for the first time with effect from 1 January
2021.
- IFRS 16 COVID-19 Related Rent Concessions amendments
The amendment is effective for annual periods beginning on 1
June 2020 and generally requires prospective application.
5. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION
UNCERTAINTY
In the application of the Group's accounting policies,
management is required to make judgments, estimates and assumptions
about the carrying amounts of assets and liabilities that are not
readily apparent from other sources. The estimates and associated
assumptions are based on historical experience and other factors
that are considered to be relevant. Actual results may differ from
these estimates.
The estimates and underlying assumptions are reviewed on an
ongoing basis. Revisions to accounting estimates are recognised in
the period in which the estimate is revised, if the revision
affects only that period, or in the period of the revision and
future periods, if the revision affects both current and future
periods.
The key judgements and sources of estimation uncertainty remain
the same as disclosed in Jadestone's audited consolidated financial
statements for the year ended 31 December 2020 .
6. OPERATING COSTS
Six months Six months Twelve months
ended ended ended
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
------------------------------- ----------- ----------- --------------
Production costs 61,951 44,466 105,338
Transportation costs 541 - -
----------- ----------- --------------
Total production costs 62,492 44,466 105,338
=========== =========== ==============
Depletion and amortisation
of oil and
gas properties 33,054 30,146 67,813
Depreciation of plant
equipment and
right-of-use assets 6,643 9,084 16,829
----------- ----------- --------------
Total depletion, depreciation
and
amoritisation 39,697 39,230 84,642
=========== =========== ==============
Corporate costs 12,230 15,506 25,471
Exploration expenses - 972 972
Other operating expenses 271 164 475
----------- ----------- --------------
Total other expenses 12,501 16,642 26,918
=========== =========== ==============
7. IMPAIRMENT OF ASSETS
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
-------------------------- ------------ ------------ --------------
Impairment of intangible
exploration
assets - - 50,455
============= =========== ==============
8. FINANCE COSTS
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
---------------------- ----------- ----------- --------------
Interest expense and
others 1,465 3,671 6,292
Accretion expense 2,469 3,163 6,363
3,934 6,834 12,655
=========== =========== ==============
9. INCOME TAX EXPENSE
The Company is tax resident in Singapore and therefore is
subjected to Singapore's domestic corporate tax rate of 17%. The
subsidiaries are resident for tax purposes in the territories in
which they operate.
The current period tax charge of US$8.7 million (H1 2020: US$
7.4 million) was generated through operations in Australia,
including PRRT at 40% and a corporate tax rate of 30%. No other
locations generated taxable profits.
Current income tax expense of US$8.9 million (H1 2020: US$10.5
million) consists of corporate income tax expense of US$11.4
million, offset by a PRRT tax credit of US$2.5 million, with a PRRT
refund received in August, as annual deductible cash payments
exceeded assessable cash receipts.
A deferred tax credit of US$0.2 million (H1 2020: US$3.1
million) has arisen from timing differences between the tax and
accounting treatment of depreciation of oil and gas properties.
10. PROFIT PER ORDINARY SHARE
The calculation of the basic and diluted profit per share is
based on the following data:
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
------------------------------ ----------- ----------- --------------
Profit for the purposes
of basic and
diluted per share, being
the net profit
for the period attributable
to equity
holders of the Company 2,495 5,360 (60,178)
=========== =========== ==============
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
Number Number Number
------------------------------ ------------ ------------ --------------
Weighted average number
of ordinary
shares for the purposes
of basic EPS 462,894,872 461,042,811 463,553,521
Effect of dilutive potential
ordinary
shares - share options 6,100,692 3,990,155 -
------------ ------------ --------------
Weighted average number
of ordinary
shares for the purposes
of diluted EPS 468,995,564 465,032,966 463,553,521
============ ============ ==============
The calculation of diluted EPS for the six months ended 30 June
2021 includes 6,100,692 of weighted average dilutive ordinary
shares available for exercise from in-the-money vested options (six
months ended 30 June 2020: 3,990,155). Additionally, 407,842 of
weighted average potential ordinary shares available for exercise,
are excluded as they are out-of-the-money (six months ended 30 June
2020: 607,821).
For the full year ended 31 December 2020, there were 4,679,402
of potential ordinary shares associated with share options which
were anti-dilutive.
Six months Six months Twelve
ended ended months ended
30 June 30 June 31 December
2021 2020 2020
Earnings/(Loss) per share Unaudited Unaudited Audited
(US$)
* Basic 0.01 0.01 (0.13)
========== ========== =============
* Diluted 0.01 0.01 (0.13)
========== ========== =============
11. INTANGIBLE EXPLORATION ASSETS
Total
USD'000
--------------------------------------- ---------
Cost
As at 1 January 2020 117,440
Additions 17,665
---------
As at 30 June 2020 135,105
Acquisition of Lemang PSC 14,825
Additions 1,195
As at 31 December 2020/1 January 2021 151,125
Additions 1,832
Reversal (6,059)
Written off (50,455)
---------
As at 30 June 2021 96,443
=========
Impairment
As at 1 January 2020/30 June 2020 -
Additions 50,455
---------
As at 31 December 2020/1 January 2021 50,455
Written off (50,455)
---------
As at 30 June 2021 -
=========
Net book value
As at 30 June 2020 (unaudited) 135,105
=========
As at 31 December 2020 (audited) 100,670
=========
As at 30 June 2021 (unaudited) 96,443
=========
In November 2020, Jadestone and Total voluntarily surrendered
their entire combined 100% interest in SC56 to the Philippines
Department of Energy ("DOE"). As a result, the SC56 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 Q2 2021.
The US$6.0 million reversal in H1 2021 relates to an
overprovision of costs owed to a third party contractor joint
venture. The overprovision was identified following an assessment
of actual costs incurred by the third party contractor.
12. PROPERTY, PLANT AND EQUIPMENT
Oil and Plant Right-of-use
gas properties and equipment assets Total
USD'000 USD'000 USD'000 USD'000
------------------------------ ---------------- --------------- ------------- ----------
Cost
As at 1 January 2020 492,985 4,139 74,663 571,787
Additions 1,750 106 760 2,616
Termination - - (307) (307)
Adjustment - - (394) (394)
---------------- --------------- ------------- ----------
As at 30 June 2020 494,735 4,245 74,722 573,702
Changes in asset restoration
obligations (725) - - (725)
Additions 2,982 367 131 3,480
Termination - - (29,339) (29,339)
As at 31 December
2020/
1 January 2021 496,992 4,612 45,514 547,118
Additions 14,173 216 1,044 15,433
As at 30 June 2021 511,165 4,828 46,558 562,551
================ =============== ============= ==========
Accumulated depletion,
depreciation and
amortisation
As at 1 January 2020 111,311 2,359 14,876 128,546
Charge for the period 35,595 206 8,878 44,679
Termination - - (102) (102)
---------------- --------------- ------------- ----------
As at 30 June 2020 146,906 2,565 23,652 173,123
Charge for the period 32,410 395 7,350 40,155
Termination - - (9,161) (9,161)
As at 31 December
2020/
1 January 2021 179,316 2,960 21,841 204,117
Charge for the period 28,224 284 6,359 34,867
As at 30 June 2021 207,540 3,244 28,200 238,984
Net book value
As at 30 June 2020
(unaudited) 347,829 1,680 51,070 400,579
As at 31 December
2020 (audited) 317,676 1,652 23,673 343,001
As at 30 June 2021
(unaudited) 303,625 1,584 18,358 323,567
13. TRADE AND OTHER RECEIVABLES
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Non-current
VAT receivables 4,451 - 4,404
Current
Trade receivables 46,291 1 106
Prepayments 6,093 2,208 2,012
Other receivables and deposits 6,621 5,759 4,273
PRRT receivables 2,496 3,883 -
GST/VAT receivables 1,634 786 719
63,135 12,637 7,110
67,586 12,637 11,514
Provision for doubtful debts
At beginning of period/year - - -
Addition 201 - -
At end of period/year 201 - -
A trade receivable of US$46.1 million arising from a June 2021
Montara lifting was received in July 2021.
14. SHARE CAPITAL
Authorised ordinary shares
Unlimited number of ordinary voting shares with par value of at
GBP0.001.
No. of shares USD'000
Issued and fully paid
As at 1 January 2020/30 June 2020 461,042,811 466,573
Issued during the period 800,000 406
-----------
As at 31 December 2020/1 January 2021 461,842,811 466,979
Issued during the period 1,856,666 799
Capital reduction, at GBP0.499 each - (467,386)
As at 30 June 2021 463,699,477 392
===========
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.
In the six months ended 30 June 2021, the Group granted to its
employees 2.9 million of share options, 1.1 million of performance
shares and 0.1 million of restricted share units (H1 2020: 6.5
million of share options; 0.6 million of performance shares and 0.1
million of restricted share units) in respect of achievement of
2020 performance objectives.
15. MERGER RESERVE
The merger reserve arose from the difference between the
carrying value and the nominal value of the shares of the Company,
following completion of the internal reorganisation (Note 3 and
4).
16. PROVISIONS
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Non-current
Asset restoration obligations 286,219 278,543 283,750
Others 4,474 4,651 4,474
290,693 283,194 288,224
Current
Others 3,091 1,705 4,558
293,784 284,899 292,782
17. BORROWINGS
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Current secured borrowings
Reserves based lending facility - 25,053 7,296
18. TRADE AND OTHER PAYABLES
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Trade payables 3,377 6,325 10,131
Other payables 1,662 84 2,004
Accruals 17,714 16,126 20,047
GST/VAT payables 7 39 10
22,760 22,574 32,192
19. DERIVATIVE FINANCIAL INSTRUMENTS
30 June 30 June 31 December
2021 2020 2020
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
-----------
Derivative financial assets/(liabilities)
Designated as cash flow hedges
Commodity capped swap - 8,341 -
===========
Carried at fair value though
profit or loss
Commodity swap - 2,076 (471)
===========
The fair values of the commodity swap were classified as Level 2
and calculated using market prices that the Group would pay or
receive to settle those swap contracts.
20. 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 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 Corporate Total
USD'000 USD'000 USD'000 USD'000
Six months ended 30 June 2021 (unaudited)
Revenue
Liquids revenue 138,158 - - 138,158
Hedging income - - - -
138,158 - - 138,158
Production costs (62,492) - - (62,492)
DD&A (39,261) (139) (297) (39,697)
Staff costs (5,137) (1,397) (5,533) (12,067)
Other expenses (8,807) (897) (2,797) (12,501)
Other income 3,257 36 388 3,681
Finance costs (3,907) (26) (1) (3,934)
Profit/(Loss) before tax 21,811 (2,423) (8,240) 11,148
Additions to non-current
assets 14,971 2,145 196 17,312
Non-current assets 329,830 93,789 842 424,461
Six months ended 30 June 2020 (unaudited)
Revenue
Liquids revenue 91,970 - - 91,970
Hedging income 23,699 - - 23,699
115,669 - - 115,669
Production costs (44,466) - - (44,466)
DD&A (39,036) (56) (138) (39,230)
Staff costs (5,965) (907) (4,553) (11,425)
Other expenses (5,055) (8,895) (2,692) (16,642)
Other income 4,269 11,087 - 15,356
Finance costs (6,823) (1) (10) (6,834)
Other financial gains 359 - - 359
Profit/(Loss) before tax 18,952 1,228 (7,393) 12,787
Additions to non-current
assets 7,576 12,288 417 20,281
Non-current assets 416,276 128,394 1,014 545,684
Producing Exploration/
assets Development
Australia SEA Corporate Total
USD'000 USD'000 USD'000 USD'000
Twelve months ended 31 December 2020 (audited)
Revenue
Liquids revenue 186,572 - - 186,572
Hedging income 31,366 - - 31,366
217,938 - - 217,938
Production costs (105,338) - - (105,338)
DD&A (84,024) (110) (508) (84,642)
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 12,084 - 26,376
Finance costs (12,625) (29) (1) (12,655)
Other financial gains 359 - - 359
Profit/(Loss) before tax 5,505 (50,428) (12,315) (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.
21. EVENT AFTER THE REPORTING PERIOD
Completion of acquisition of SapuraOMV Peninsular Malaysia
assets
On 1 August 2021, all conditions precedent to closing the
acquisition of the SapuraOMV Peninsular Malaysia assets were
satisfied and the Group proceeded to close the acquisition,
including the transfer of operatorship of PM329 PSC and PM323
PSC.
Glossary
GBP British pound sterling
2P the sum of proved and probable reserves, reflecting
those reserves with 50% probability of quantities
actually recovered being equal or greater to the
sum of estimated proved plus probable reserves
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
bscf billion standard cubic feet equivalent
Btu British thermal unit
Btu/d British thermal unit per day
BBtu/d Billion Btu/d
capex capital expenditures
CIF used here to characterise the shipping arrangement
typically negotiated for Stag post termination
of Dampier Spirit FSO, whereby charges such as
cost, insurance and freight are paid by Jadestone
while the crude oil is in transit to the buyer
DD&A depletion, depreciation and amortisation
EBITDAX earnings before interest tax, depreciation, amortisation
and exploration
EPS earnings per share
FOB used here to characterise the shipping arrangement
typically negotiated for Montara liftings, and
for Stag liftings during the period when the Dampier
Spirit FSO was in place, under which liftings were
agreed on a free-on-board basis at the offtake
hose of the FPSO (Montara)/FSO (Stag)
FPSO floating production storage and offloading
FSO floating storage and offloading
GB pence, Great Britain pence
GBp
GHG greenhouse gases
GST goods and services tax
IFRS International Financial Reporting Standards
JEI Jadestone Energy Inc.
mm million
mmBtu million British thermal unit
opex operating expenditures
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
SEA Southeast Asia
US$ or USD United States dollar
VAT value-added tax
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END
IR FIFVEARIAIIL
(END) Dow Jones Newswires
September 09, 2021 02:00 ET (06:00 GMT)
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