Full Year Results and Final Dividend Announcement

2020 Full Year Results and Final Dividend Announcement

 

22 April 2021-Singapore: Jadestone Energy Inc. (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 2020, and announces its intended final dividend.  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 2020, the Jadestone business delivered strong operating cash flow, declared its maiden dividend, acquired a near-term gas development asset in Indonesia, and exited the year with double the net cash it had at the beginning of January.

"This was accomplished against an external environment that tested the resilience of our business model, and indeed for some of our peers in the industry, challenged their very existence.  Through a mix of well-timed hedging gains, rapid adjustments to our spending plans and a hard interrogation of our cost base, we successfully protected our balance sheet while rephasing production growth to coincide with a higher price environment.  At the same time, we maintained our steadfast commitment to our principles of environmental stewardship, social responsibility, and high governance standards, and have recorded no major incidents on any of these fronts.

 

"Our balance sheet has grown stronger still in 2021.  We are generating higher unit cash flows as benchmark oil prices have recovered and pricing premiums remain strong.  Also, as planned, we have now fully repaid our reserves based loan, being completely debt free as of the end of Q1 2021.  We are continuing in our pursuit of constant improvement across the business, and continue to find opportunities for greater efficiency in addition to having locked in 25% of the cash flow savings we implemented in 2020 through Project Clover. 

 

"Our commitment to ongoing shareholder returns remains intact too, and I am pleased to announce the final portion of our 2020 dividend today, as well as re-affirming our dividend policy for 2021 and beyond.  We are constantly focussed on delivering value for shareholders and see both organic, and inorganic growth, as well as direct shareholder returns as key components.

 

"I would also like to take the opportunity to offer my thanks to the entire Jadestone team, and to their families for remaining strong and resilient through what has been a very challenging year.  The performance we delivered in 2020 is a testament to the high calibre of our workforce, and with their unwavering support for the business, we are well positioned to continue delivering value for shareholders in 2021 and beyond."

 

Paul Blakeley

 

EXECUTIVE DIRECTOR,

PRESIDENT AND CHIEF EXECUTIVE OFFICER

 

 

 

2020 SUMMARY

 

·    Full year production of 11,438 bbls/d, 15% down on 2019 from 13,531 bbls/d, due to natural field production decline and an intentional deferral of well workovers and well interventions during a period of prolonged lower oil prices and heightened COVID-19 restrictions on moving people and equipment;

·    Good performance against Target Zero, with no reportable environmental incidents or injuries.  Received one regulatory enforcement notice related to internal processes, which has now been resolved;

·    Reduced overall greenhouse gas emissions by 15%, led by a 40% reduction in flaring;

·    Net revenue of US$217.9 million in 2020, down 33% from US$325.4 million in the prior year, due to the decline in oil prices associated with the impact of COVID-19 and a slightly lower liftings, partly offset by higher hedging income;

·    Average benchmark Dated Brent prices 35% lower at US$41.84/bbl in 2020, compared to US$64.21/bbl in 2019.  Jadestone's average realised price¹ in 2020 was US$44.79/bbl, down 35% from US$69.07/bbl in 2019, as the Group continued to realise strong premiums on lifted cargos in 2020, at US$4.17/bbl (2019: US$4.97/bbl).  Inclusive of hedges, the average realised price was US$52.32/bbl (2019: US$72.39/bbl), compared to Dated Brent of US$41.84/bbl (2019: US$64.21/bbl);

·    Total crude oil sold for the year was 4,165,612 bbls, 7% down on 2019 of 4,496,164 bbls, from a total of 10 liftings (2019: 10), largely due to lower production;

·    Costs of production in 2020 were US$105.3 million, a decrease of 12% from 2019.  This equates to unit operating costs² of US$23.10/bbl, broadly in line with 2019 of US$22.85/bbl, despite the lower production in 2020, largely as a result of the various cash flow savings initiatives delivered under Project Clover;

·    An impairment loss of US$50.5 million (2019: nil) due to the relinquishment of Philippines service contract 56 ("SC56"), announced in November 2020, reflecting the capitalised intangible exploration value of US$50.5 million, most of which relates to spending by the Group's previous management team;

·    Net post tax loss of US$60.2 million, compared to net profit after tax of US$40.5 million in 2019, reflecting the impairment of SC56, as well as the 35% drop in realised prices and lower production levels;

·    Strong operating cashflow generation, despite the extraordinary conditions during the year, with positive operating cash flows of US$86.9 million, before movements in working capital, down 51% compared to 2019 of US$176.9 million; 

·    Capital expenditure of US$24.1 million down 69% compared to the prior year.  Management deferred approximately US$160.0 million of spending intended for organic growth projects amidst the COVID-19 pandemic;

·    Project Clover cashflow savings in 2020, in line with plan, of US$33.0 million, with approximately 25% of these savings reflecting structural changes in Jadestone's future cost base;

·    Completion of the acquisition of a 90% operated interest in the Lemang PSC in December 2020, for a cash consideration of US$12.1 million, including closing statement adjustments;

·    Gross cash and net cash as at 31 December 2020 of US$89.4 million and US$82.1 million (2019: US$99.4 million and US$39.3 million), respectively, a more than doubling of the net cash balance year-on-year;

·    Following the final scheduled repayment on the Group's reserved based loan on 31 March 2021 of US$7.4 million, Jadestone's capital structure is now entirely debt free;

·    Maari acquisition long stop date revised to 30 June 2021, with both the seller and Jadestone continuing to work together to try to close the transaction as soon as possible;

·    An intention to recommend a final dividend of USȼ1.08/share (US$0.0108/share), a distribution of US$5.0 million, following the completion of the internal reorganisation and the planned capital reduction at Jadestone Energy plc, and following approval of that dividend by shareholders at the planned annual general meeting, to be paid in the latter part of June.  This results in total dividends in respect of 2020, Jadestone's maiden year of dividends, of US$7.5 million;

·    Adoption of the Quoted Companies Alliance corporate governance code as part of the Company's ongoing pivot toward practices more typical of a UK company; and

·    Jadestone's internal reorganisation is expected to become effective on 23 April 2021, resulting in a new UK-based parent company for the Group, Jadestone Energy plc, unlocking significant further cash flow savings for the Company and for shareholders.

 

 

¹ Realised oil price represents the actual selling price, before any impact from hedging. 

² Unit operating costs per barrel before workovers and movement in inventories, but including net lease payments and certain other adjustments (see non-IFRS measures below).

 

 

 

2021 OUTLOOK

 

·    Average crude oil production in 2021 of 11,500-13,500 bbls/d, assuming the successful drilling of the H6 infill well at Montara, two Skua well workovers, and completion of the Group's acquisition of a 69% operated interest in Maari at the end of H1 2021;

·    Maari's contribution to the full year production guidance range is assumed to be 1,500 bbls/d on an annualised basis (i.e. 3,000 bbls/d average production in H2 2021), and with the completion of Maari's MR6 well workover in early May, there is scope for additional production upside.  The effective date of the acquisition is 1 January 2019.  Conditional on completion of the acquisition, the entire economic benefit from Maari barrels produced from the effective date up to the closing date will accrue to the Group;

·    Average unit production costs of US$25.50-29.50/bbl, a slight increase on 2020, reflecting approximately             US$1.00/bbl of rephased costs from 2020 resulting from Project Clover, a stronger Australian dollar compared to 2020, and additional one-off repairs and maintenance activity in Australia;

·    Capital expenditures of US$85.0-95.0 million, including drilling the H6 infill well and the two Skua well workovers;

·    Commitment to continue to pay cash dividends, in keeping with the Group's dividend policy to maintain and grow dividends in line with underlying cashflow generation;

·    Further inorganic growth opportunities in the Asia Pacific region under active evaluation; and

·    Ongoing adherence to our principles on environmental, social, and governance responsibilities, including             enhanced sustainability reporting, maintaining our commitment to Target Zero with regards to deviations from safe operating parameters, and adopted the Quoted Companies Alliance corporate governance code.

 

 

Enquiries

Jadestone Energy Inc.	+65 6324 0359 (Singapore)
Paul Blakeley, President and CEO	+44 7392 940 495 (UK)
Dan Young, CFO	[email protected]
Robin Martin, Investor Relations Manager
Stifel Nicolaus Europe Limited (Nomad, Joint Broker)	+44 (0) 20 7710 7600 (UK)
Ashton Clanfield / Callum Stewart / Simon Mensley
Jefferies International Limited (Joint Broker)	+44 (0) 20 7029 8000 (UK)
Tony White/ Will Soutar
Camarco (Public Relations Advisor)	+44 (0) 203 757 4980 (UK)
Billy Clegg / James Crothers	[email protected]

 

Conference call and webcast

The management team will host an investor and analyst conference call at 4:00 p.m. (Singapore) and 9:00 a.m. (London) today, 22 April 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 year ended 31 December 2020 will be available on the Company's website at: www.jadestone-energy.com/investor-relations/

 

 

 

Webcast link: https://produceredition.webcasts.com/starthere.jsp?ei=1451257&tp_key=3401948e85 

Event conference title: Jadestone Energy Inc. - Full Year 2020 Results
Start time: 4:00 p.m. (Singapore), 9:00 a.m. (London)
Date: 22 April 2021
Conference ID: 32221662

 

Dial-in number details:

 

Country	Dial-In Numbers
Australia	1800076068
Canada (Toronto)	416-764-8688
Canada (Toll free)	888-390-0546
France	0800916834
Germany	08007240293
Germany (Mobile)	08007240293
Hong Kong	800962712
Indonesia	0078030208221
Ireland	1800939111
Ireland (Mobile)	1800939111
Japan	006633812569
Malaysia	0018030208221
New Zealand	0800453421
Singapore	8001013217
Switzerland	0800312635
Switzerland (Mobile)	0800312635
United Kingdom	08006522435
United States (Toll free)	888-0390-0546

 

 

DIVIDEND

 

The Directors intend to recommend a 2020 final dividend of USȼ1.08/share, or US$5.0 million in total.  The Directors intend to recommend the 2020 final dividend following the completion of the internal restructuring, including the arrangement agreement becoming effective on or around 23 April 2021, and the completion of the capital reduction of Jadestone Energy plc which is expected to become effective during the second half of May.  At that point, the Directors will confirm the recommended 2020 final dividend, including the record date and the ex dividend date.  Jadestone Energy plc's first annual general meeting ("AGM") is scheduled for 16 June 2021, at which time it is expected that shareholders will vote to approve this 2020 final dividend.  The actual payment date is expected to occur seven calendar days following the AGM.

 

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.  It achieves this by ensuring it reduces its environmental footprint through the life cycle of developments and by bringing social and economic benefits for people associated with its operations.

 

Jadestone's ESG Framework has evolved over the course of 2020 to depict its continued alignment with wider societal challenges addressed by the 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 and purpose.  It has also considered how these specific goals relate to the material matters, orientating its 2021 strategic corporate goals around them. 

 

Jadestone's ESG commitments include:

 

·    Continually improve Jadestone's environment, health, safety and social performance, in line with industry best practice;

·    Uphold the highest standards of governance and obey the law in the countries and communities where it operates;

·    Commit to reducing greenhouse gas emissions from Jadestone operations; and

·    Consider the ESG expectations of its stakeholders.

 

In 2020, the Group has maintained safe operations at all assets, with no significant recordable personnel or environmental incidents, and no disruptions to offshore operations due to the COVID-19 pandemic.  Jadestone has continued its focus on improving the carbon footprint of its operations, targeting reductions in flaring and diesel use, exceeding both targets over three-fold.  As per Jadestone's business strategy of acquiring mature, mid-life assets and transforming them into more productive entities, the Group has invested in efficiency measures and introduced improvements to its Montara asset's operational practices.  Through an increase of unprocessed gas reinjection at the site, an estimated 90,000 t of CO₂-e of emissions was eliminated.  These efforts have resulted in overall GHG emissions being 15% less in 2020 when compared to the 2019 baseline¹.

 

Jadestone has also increased its alignment with the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD) in its reporting and programmes, with major progress around climate risk and governance.  Jadestone has also 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.

 

Finally, the Board has adopted the Quoted Companies Alliance ("QCA") corporate governance code, effective from 31 December 2020, as part of Jadestone's ongoing pivot from Canadian to UK corporate governance practices and norms.  The resultant changes that arise from the adoption of the QCA corporate governance code have been implemented and are a testimony to the Company's commitment to further strengthening transparent and effective corporate governance practices.

 

The Company's 2020 Sustainability Report, as part of the 2020 Annual Report provides further details and enhanced disclosures on the Group's ESG priorities and progress to date.

 

 

 

¹ Jadestone's 2020 GHG emissions were compared to a full 2019 emissions data set, inclusive of the Montara asset operations during the period January - July 2019, prior to JSE becoming the site's operator in 2019.

 

OPERATIONAL REVIEW

 

Producing Assets

 

Australia

 

Montara Project

 

The Montara Project is located in production licenses AC/L7 and AC/L8, offshore Western Australia, in a water depth of approximately 77 meters.  The Montara assets, comprising the three separate fields being Montara, Skua and Swift/Swallow, are produced through an owned floating production storage and offloading vessel, the Montara Venture.  As at 31 December 2020, the Montara assets had proven plus probable reserves of 22.7mm 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 2020 ranged between a discount of US$2.19/bbl to a premium of US$7.54/bbl due to the impacts on demand of COVID-19.  The most recent lifting was agreed at a premium of US$0.66/bbl.

 

During the year, the Group completed a 3D seismic acquisition programme covering the AC/L7 and AC/L8 licences, to improve reservoir imaging for future infill wells and to assess prospects for future exploration targets.  Interpretation work on the seismic data is being carried out by licence area and is expected to be completed by 2023.

 

Production averaged 9,045 bbls/d in 2020 (2019: 10,483 bbls/d).  Lower production was primarily the result of natural field production decline, and identified problems within the well bores of the two Skua field wells, which were taken offline while workovers are planned.

 

During 2021, the Group plans to drill the H6 well, which was deferred from 2020 in response to COVID-19 and to perform the two Skua workovers.  In the meantime, production volumes deferred from the Skua satellite field are being substantially offset by increased rates from the Swift and Swallow fields.

 

There were six liftings in 2020, resulting in total sales of 3,221,258 bbls, compared to 3,577,199 bbls in 2019 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 meters.  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 2020 ranged between US$5.50/bbl to US$21.00/bbl, due to the impacts on demand from COVID-19.  The most recent lifting was agreed at a premium of US$13.88/bbl.

 

In May 2020, the owners of the Dampier Spirit floating storage and offloading vessel ("FSO") advised the Group of their intention to retire the vessel.  In response, the Group adopted a tanker shuttle operating model, whereby modern double hulled tankers are loaded directly, on a rotational basis, thus eliminating the need for ship to ship oil transfers in field.  The new model commenced in September 2020, immediately following the departure of the Dampier Spirit.  The tanker shuttle operating model offers environmental benefits relative to the permanently moored Dampier Spirit, as well as cost savings of approximately 20% per annum.

 

Reduced manning on the facility, due to restrictions arising from COVID-19, impacted upon the ability to conduct major activities, other than mandatory and core maintenance requirements.  To work within these restrictions and in view of the lower oil price during the year, workover activity was reduced in the second and third quarters, before picking up again in the last quarter of 2020.  

 

Production was 2,394 bbls/d in 2020, compared to 3,049 bbls/d in 2019.  Lower production was primarily the result of the pull-back on well workovers during a period of prolonged lower oil prices and amidst heightened COVID-19 restrictions and costs on moving people and equipment.

 

There were four liftings in 2020, for total sales of 944,354 bbls, compared to 918,961 bbls in 2019 from the same number of liftings.

 

During 2021, the Group will continue the well workover programme, primarily as a result of the need to replace electronic submersible pumps at the end of their useful lives, and will conduct well planning work, in preparation for future drilling activities.

 

New Zealand

 

Maari Oilfield

 

On 16 November 2019, the Group executed a sale and purchase agreement ("SPA") with OMV New Zealand Limited ("OMV New Zealand"), to acquire an operated 69% interest in the Maari project, shallow water offshore New Zealand, for a total 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 Ministerial consent.  Jadestone and OMV New Zealand continue to work towards completion of the transaction.  The SPA long stop date has been revised to 30 June 2021.  The Group will assume the operatorship 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 field holds 2P audited reserves of 10.6mm barrels of oil, net to Jadestone's 69% interest. 

 

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.

 

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.  In mid-March 2020, amid delays in Vietnamese Government approvals and the drop in global oil prices related to COVID-19, the Group opted to delay the project, as part of a review of its 2020 capital programme.

 

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

 

On 29 June 2020, the Group executed an acquisition agreement with Mandala Energy Lemang Pte Ltd, to acquire an operated 90% interest in the Lemang PSC, onshore Indonesia, for an acquisition price of US$16.5 million, comprising cash consideration of US$12.1 million after closing statement adjustments and future estimated fair value potential contingent payments of US$4.4 million.  

 

 

The Lemang PSC is located onshore Sumatra, Indonesia.  The block includes the Akatara gas field, with a net to Jadestone 2C resource of 17.2 mm 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 in December 2019. 

 

The acquisition closed on 11 December 2020, following the receipt of governmental approval of the assignment of the interest and of the Group's appointment as operator.

 

The Group intends to commence a gas development project on the Lemang PSC and current efforts are focused on finalising a heads of agreement on gas sales, to be followed by a gas sales agreement with a buyer before seeking formal field development sanction.  The timeline for the Lemang development is highly flexible, and at Jadestone's discretion. 

 

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").  The exploration period on the block expired on 1 September 2020.  During the year, Total was granted a 12-month extension on the exploration period until 1 September 2021, with the COVID-19 pandemic representing a force majeure event under the service contract.

 

Following management's strategic review of available options for the asset, mutual agreement was reached in mid-November between Jadestone and Total regarding the voluntary relinquishment of SC56.  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 is 21 December 2020. 

 

SC56 was inherited from the former Mitra Energy management team and was not an asset consistent with Jadestone's strategy.  It remained in the Jadestone portfolio due to the carried well commitment, which was intended to provide a cost-free option to further test this frontier basin/new basin entry opportunity.  It was important for the Group and our shareholders to pursue this potential to its ultimate conclusion.  The Mitra Energy management team had incurred an accumulated US$49.4 million of costs in capitalised exploration value by 30 June 2016.  Jadestone spent a further US$1.1 million over the last four-and-a-half years.

 

The relinquishment decision has resulted in the recognition of an impairment in Q4 2020 in relation to the capitalised intangible exploration value of US$50.5 million.             

 

Following the termination, the Group is liable for 25% of the unfulfilled minimum work programme as at the termination date.  The total unfulfilled minimum work programme amount has been submitted by Total to the DOE and is currently under review.  The Group's share of the unfulfilled minimum work programme will be funded from the net arbitration proceeds of US$2.2 million received from Total in Q1 2020.

 

Service Contract 57 ("SC57")

 

The Group holds a 21% working interest in SC57, which has been under force majeure since 2011, and these conditions are not expected to change in the foreseeable future.

 

 

 

 

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 2020.

 

USD'000 except where indicated	2020	2019
Sales volume, barrels (bbls)	4,165,612	4,496,164
Production, bbls/day	11,438	13,531
Realised oil price, $/bbl1	44.79	69.07
Revenue	217,938	325,406
Production costs	(105,338)	(119,898)
Operating costs/bbl ($/bbl)2	23.10	22.85
Adjusted EBITDAX2	62,582	187,505
Depletion, depreciation & amortisation costs/bbl ($/bbl)	16.24	16.94
Impairment	50,455	-
(Loss)/Profit before tax	(57,238)	73,281
(Loss)/Profit after tax	(60,178)	40,505
(Loss)/Earnings per ordinary share: basic & diluted	(0.13)	0.09
Operating cash flows before movement in working capital	86,883	176,908
Capital expenditure	24,065	77,240
Outstanding debt2	7,386	50,144
Net cash2	82,055	39,275

 

Benchmark commodity price and realised price

 

The annual average benchmark Brent crude decreased 35% to US$41.84/bbl, compared to US$64.21/bbl.  The average benchmark price based on liftings was US$40.61/bbl in 2020, compared to 2019 at US$64.13/bbl. 

 

The actual average realised price in 2020 decreased in line with the benchmark price, by 35% to US$44.79/bbl, compared to US$69.07/bbl in 2019.  The average annual premium in the year was US$4.17/bbl, compared to 2019 at US$4.97/bbl.  The premiums have gradually improved from the oil price trough in Q2 2020, with the Group achieving US$13.88/bbl and US$0.66/bbl from its latest liftings of Stag and Montara crude oil, respectively.

 

Amidst an uncertain global outlook, including second and third waves of COVID-19 pandemic, the Group has entered into Dated Brent swaps covering approximately 30% of planned H1 2020 production at an average swap price of U$55.16/bbl, to support the 2020 planned organic growth capital programme.

 

Production and liftings

 

The Group generated average production in 2020 of 11,438 bbls/d, compared to 13,531 bbls/d in 2019.  Production at both Montara and Stag was lower compared to 2019, primarily the result of natural field production decline in addition to deferred production due to an intentional pull-back on well workovers during a period of prolonged lower oil prices and amidst heightened COVID-19 restrictions and costs on moving people and equipment. 

 

 

¹ Realised oil price represents the actual selling price, net of marketing fees, and before the net impact from commodity hedging instruments. Inclusive of hedges, the average realised price in 2020 was US$52.32/bbl (2019: US$72.39/bbl), compared to average annual Dated Brent of US$41.84/bbl (2019: US$64.21/bbl).

² Operating cost per bbl, adjusted EBITDAX, outstanding debt and net cash are non-IFRS measures and are explained in below.

 

The Group had 10 liftings during the year (2019: 10), resulting in sales of 4,165,612 bbls (2019: 4,496,164 bbls), reflecting the lower production compared to 2019.

 

Revenue

 

The Group generated US$217.9 million of revenues in 2020, compared to US$325.4 million from 2019, a drop of 33%.  Revenue derived from the sale of crude oil declined by US$124.0 million or 40%, from US$310.5 million in 2019 to US$186.6 million in 2020, due to:

 

·      Lower average realised prices in 2020, compared to 2019 (US$44.79/bbl vs US$69.07/bbl), giving rise to a decline of US$101.2 million; and

·      Lower lifted volumes in 2020 at 4.2mm bbls, compared to 4.5mm bbls in 2019, generating an additional decline of US$22.8 million.

 

This was partly offset by an increase in hedging income of US$31.4 million, more than double 2019's hedging income of US$14.9 million. 

 

Production costs

 

Production costs declined 12% in 2020 to US$105.3 million, from US$119.9 million in 2019, predominately due to:

 

·      Logistics costs were lower by US$6.3 million compared to 2019, as a result of the reduction in the usage of transportation facilities in the production process, in line with the decreased production in 2020;

·      Workover costs were US$8.6 million lower compared to 2019, due to the decision to defer several well interventions amid the costs and logistics challenges posed by COVID-19.  In addition, workover costs in 2019 were unusually high due to the non-routine replacement work associated with the riserless light well intervention;

·      Operational staff costs were lower by US$2.9 million, as part of the Project Clover cost savings initiatives implemented by the Group in response to COVID-19; and

·      A positive variance of US$4.5 million in movement of crude inventories, reflecting the year-on-year differential of the Group's inventories on hand at year end.  There were 601,999 bbls in inventory as at 31 December 2020, compared to 581,133 bbls as at 31 December 2019.

 

Unit operating costs per barrel were US$23.10/bbl (2019: US$22.85/bbl), before workovers and movement in inventories, but including net lease payments and certain other adjustments (see non IFRS measures below), with the variance a result of lower production rates during the year.

 

DD&A                                                                                       

 

DD&A charges were US$84.6 million in 2020, compared to US$90.7 million in 2019, reflecting lower production during the year.  The depletion cost on a unit basis was US$16.24/bbl in 2020 (2019: US$16.94/bbl), predominately due to a technical adjustment on Montara reserves at December 2019 vs December 2018.

 

Other expenses

 

Other expenses in 2020 totalled US$26.9 million (2019: US$9.4 million).  The variance of US$17.5 million was predominately due to:

 

·      One-off litigation costs related to the settlement of SC56 of US$8.8 million and 05-1 PSC of US$0.3 million (see also other income, with respect to the arbitration awards to Jadestone that more than offset these costs);

·      Rig contract deferral costs in Australia of US$3.0 million, following the decision to defer the Australian 2020 drilling campaign in response to the impact of COVID-19;

·      Unrealised foreign exchange loss of US$2.6 million (2019: US$0.2 million), due to the depreciation of the United States Dollar against the Australian Dollar; and

·      Professional and consultancy charges of US$1.3 million, in support of several business development projects in 2020, including the acquisition of the Lemang PSC.

 

Other income

 

Other income was US$26.4 million (2019: US$3.0 million).  The variance of US$23.4 million was predominately due to:

 

·      Monetary damages awarded of US$11.1 million, for the breach of the SC56 farm out agreement by Total;

·      Release of the provision made in relation to the Stag FSO of US$5.0 million, payable to the crew at the expiration of the Dampier Spirit FSO lease.  Following the termination of the lease, the Group was no longer required to make this payment, and the provision reversed;

·      Rebate income of US$3.6 million from the Group's helicopter lease contract, arising from the sublease of the right-of-use assets to a third party;

·      Gain of US$1.4 million from the termination of the Dampier Spirit FSO lease in September 2020; and

·      Settlement sum of US$1.0 million received from Inpex to resolve the dispute over the Block 05-1 PSC.

 

Impairment

 

The Group recorded an impairment of US$50.5 million associated with the capitalised intangible exploration costs at SC56, as the costs are no longer deemed recoverable.  In Q4 2020, the Group and Total decided to voluntarily relinquish their interests in the block.  US$49.4 million of the impaired amount was incurred by the previous Mitra Energy management team up to 30 June 2016.

 

Taxation

 

Taxation charges declined 91% to US$2.9 million from US$32.8 million in 2019. 

 

The current tax charge was US$11.7 million, which consists of US$10.0 million of corporate tax expense and net PRRT paid of US$1.7 million, which is lower, compared to corporate tax expense of US$43.4 million and net PRRT refunded of US$1.9 million in 2019.  This was due to:

 

·      Lower corporate tax expense by US$33.4 million due to the significant decrease in realised average lifting price and slightly lower lifted volumes.  The Group was in a taxable position, despite the loss before tax position as presented in the consolidated statement of profit or loss, which was mainly the result of non-deductible expenses including the SC56 impairment and DD&A recognised for oil and gas properties; and

·      Net PRRT paid of US$1.7 million, compared to net PRRT refunded of US$1.9 million in 2019, which was predominately due to the liftings made in the first half of the year, prior to the significant decline in commodity prices, and the Group spending less on capital expenditure, resulting in lower PRRT deductibles generated, compared to 2019, when the 49H infill well was drilled.

 

The corporate tax expense was partly offset by a deferred tax credit of US$8.7 million, which consists of US$4.0 million (2019: US$20.3 million) for the unwinding of deferred tax liabilities and US$4.7 million of deferred PRRT credit (2019: expense of US$6.3 million).  The smaller unwinding of deferred tax liabilities in 2020 versus 2019 was due to the lower production and depletion charges in 2020, and hence a smaller gap between the book depletion charge and the tax charge.  The deferred PRRT credit of US$4.7 million in 2020 was due to the reduction of deferred tax liabilities associated with Stag PRRT, mostly attributable to the lower realised prices and the lower capital expenditure in 2020.

 

Impact of COVID-19

 

In view of the low crude oil price environment arising from the impacts of the COVID-19 pandemic, the Group has undertaken an impairment review on its non-financial assets, as at 31 December 2020, reflecting, among other factors, the then spot price for Dated Brent of US$50.48/bbl and the outlook for crude oil prices.  Following this review, no impairment is required with respect to the Group's producing assets in Australia (Stag and Montara), and the exploration assets in Montara and Vietnam.

 

2020 RECONCILIATION OF NET CASH

 

	US$'000	US$'000
Cash and cash equivalents, 31 December 2019		75,934
Restricted cash1, 31 December 2019		13,485
Total cash and cash equivalent, 31 December 2019		89,419
Revenue	217,938
Other operating income	19,690
Operating costs	(105,338)
Staff costs	(20,775)
General and administrative expenses	(24,632)
Cash flows from operations		86,883
Movement in working capital		25,225
Tax paid		(25,969)
Interest paid		(1,542)
Purchases of intangible exploration assets, oil and gas properties, and   plant and equipment2		(19,458)
Net cash outflows on acquisition of Lemang PSC		(11,959)
Other investing activities		257
Financing activities		(53,415)
Total cash and cash equivalent, 31 December 2020		89,441
Outstanding debt, 31 December 2020		(7,386)
Net cash3, 31 December 2020		82,055

 

Despite the dramatic fall in average realised prices in 2020, and the Group's reduced production and hence liftings amidst the pullback in workovers due to COVID-19 restrictions and the lower oil price environment, the business still generated positive operating cash flow.  Additionally, after financing activities including US$42.8 million of debt principal repayments and interest payments on the Group's RBL, the Group also generated positive organic equity free cashflow during the year (before the acquisition cost of the Lemang PSC).

 

 

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, and reconciles amounts to the nearest equivalent IFRS measure.

 

 

 

¹ Restricted cash in 2019 excludes US$10.0 million in support of a bank guarantee to a key supplier in respect of Stag's FSO vessel.

² Total capital expenditure was US$24.1 million (2019: US$77.2 million), comprising total capital expenditure paid of US$17.9 million (2019: US$68.3 million), plus accrued capital expenditure of US$6.1 million (2019: US$8.9 million).

³ Net cash is a non-IFRS measure and is explained in below.

 

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 oil 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.

 

USD'000 except where indicated		2020		2019
Production costs (reported)		105,338		119,898
Adjustments
Lease payments related to operating activity1		17,548		15,947
Movement in oil inventories2		2,806		7,337
Workover costs3		(21,686)		(30,331)
Impact from foreign exchange derivatives apportioned to production   costs4		(2,649)		-
Other income5		(3,634)		-
Non-recurring repair and maintenance6		(1,619)		-
Australian Government JobKeeper scheme		600		-
Adjusted production costs		96,704		112,851
Total production, barrels		4,186,478		4,938,867
Operating costs per barrel		23.107		22.85

 

 

 

¹ Lease payments related to operating activity are lease payments considered to be operating costs in nature, including leased helicopters for transporting offshore crews, and FSO rental fees.  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 to normalise the opex/bbl so as to enhance comparability.  The frequency of workovers can vary significantly, across periods, particularly at Stag.

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 relates to costs associated with Cyclone Damien.

⁷ The Company previously announced unaudited estimate 2020 opex/bbl of US$23.24/bbl.  This estimate was before removing the Australian Government JobKeeper scheme of US$0.6 million and upward revision of US$0.6 million to the Cyclone Damien costs noted in footnote 6, following finalisation of works.

 

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 calculation of adjusted EBITDAX is as follow:

 

USD'000	2020		2019
Revenue	217,938		325,406
Production cost	(105,338)		(119,898)
Staff cost	(21,903)		(22,027)
Impairment of assets	(50,455)		-
Other expenses	(26,918)		(9,379)
Other income, excluding interest income	26,119		-
Other financial gains	359		3,389
Unadjusted EBITDAX	39,802		177,491
Non-recurring
Net gain from oil price derivatives	(30,889)		(14,242)
Impairment of assets	50,455		-
Non-recurring opex1	8,270		23,785
Net litigation income	(3,005)		-
Rig contract deferred costs	3,000		-
Gain on contingent considerations	(359)		(3,389)
Gain from termination of FSO lease	(6,429)		-
Others2	1,737		3,860
	22,780		10,014
Adjusted EBITDAX	62,582		187,505

 

 

 

¹ Includes one-off major maintenance/well intervention activities, in particular the workover campaigns at Skua 10 and H3 in 2020, and the riserless light well intervention in 2019, as well as other non-recurring production expenditures such as the repair and maintenance costs associated with weather downtime.

² 2020 includes Montara seismic acquisition costs associated with areas outside the current license, Maari transition team costs, Australian Government JobKeeper scheme and gain on contingent considerations, while 2019 includes Montara transition team costs and gain on contingent considerations.

 

Outstanding debt

 

Total borrowings, as recorded in the Group's consolidated statement of financial position, represents the carrying amount of interest bearing debt, 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 2020, the Group had outstanding debt of US$7.4 million, which was fully repaid at the end of the first quarter of 2021.

 

USD'000		2020		2019
Long term borrowing		-		7,328
Short term borrowing		7,296		41,795
Add back: effective interest method financing costs		90		1,021
Outstanding debt		7,386		50,144

 

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.

 

USD'000		2020		2019
Outstanding debt		(7,386)		(50,144)
Cash and cash equivalents		81,996		75,934
Restricted cash		7,445		13,485
Net cash		82,055		39,275

 

Net cash is defined as the sum of cash and cash equivalents, which included the minimum working capital balance of US$15.0 million required under the Group's RBL, and restricted cash of US$7.4 million in the RBL debt service reserve account (2019: US$13.5 million), less outstanding debt.  The restricted cash in 2020, as shown here, excludes the US$1.0 million cash collateralised bank guarantee placed with the Indonesian regulator with respect to a joint study agreement entered into by the Group in Indonesia.  The restricted cash in 2019 excludes the US$10.0 million deposited in support of a bank guarantee to a key supplier in respect of the Stag FSO.  This guarantee was wound-up by the Group during the year as part of the move to the shuttle tanker model. 

  

 

2020 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 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.

 

The principal risks are currently recognised and their mitigating actions are detailed below.

 

Risk Group	Risk	Select mitigations
Business development opportunities	The Group is in a growth phase.  If there is a lack of high-quality opportunities, the anticipated growth of the business may not be achieved.  Poor due diligence or unfavorable transaction terms may add low quality assets or unexpected material liabilities to the Group.	Opportunities are assessed against a set of strict evaluation criteria.  Thorough and detailed due diligence analysis is performed, including the use of third-party experts wherever applicable.  Detailed transition plans are prepared to ensure a seamless and successful asset transition.
Capital funding	The Group will at times require external funding to finance organic growth and/or M&A opportunities. A change in investor sentiment towards funding of upstream oil & gas production and development could impact access to funds and increase debt margins.	The Group maintains a strong balance sheet by maximizing net cash to ensure sufficient liquidity within the business, and minimizing interest bearing debt. Cash forecasts are continually monitored including considering multiple scenarios for base case, and low cases with mitigations. Disciplined allocation of capital across the portfolio. Strong long-term relationships are sought and maintained with major international financial institutions.
Climate change risks	In the face of growing societal expectations and emerging policies including a tax or taxes on carbon, there are risks arising from the Group's failure to manage the impact of climate change and to demonstrate climate action. The potential impacts from emerging policy, regulation and a shift to renewable energy could impact the performance of the business and may increase costs, reduce value and restrict future opportunities.	The Group has a dedicated Climate Change Working Group to drive Jadestone's climate action agenda. Climate action priority areas include: 1) Reducing GHG 2) Increasing climate resiliency 3) Supplying cleaner energy alternatives Sustainability measures are to be disclosed and in alignment with climate related financial disclosure recommendations. ESG performance is reflected in executive KPIs and cascaded throughout business.  The Group targets top-quartile ESG performance among its peer group.
Commodity price risk	The Group's earnings are dependent on commodity prices which are influenced by global events.  A prolonged decline in oil prices will have a negative impact on revenues, margins, profitability and cashflows.	The Group maintains a continual focus on its cost structure and continually seeks cost efficiency initiatives to embed further cashflow resiliency.  The Company will use commodity price hedging to mitigate the exposure to fluctuations in oil prices during periods of elevated capital expenditure and/or debt incurrence. The company seeks to diversify its asset portfolio and reduce exposure to commodity price fluctuation through fixed price gas contracts, including the Nam Du/U Minh gas development in Vietnam and the Lemang gas and liquids project in Indonesia.
Health, safety, and environment ("HSE") risks	HSE is a key priority for the board and senior management team. The group operates in challenging locations and conditions both off and onshore. An unsafe working environment and failure of HSE standards could result in personal injury, fatality and/or reputational damage. The consequence of a failure to manage HSE risk could result in penalties, increased costs and a potential loss of a license to operate.	HSE committee oversees and sets standards for the Group. HSE performance target of zero lost time incidents.  Any lost time or near miss incidents are investigated and lessons learnt implemented promptly, alongside active monitoring of HSE standards leading and lagging indicators. The Group is committed to maintaining robust health and safety procedures including procedures in place to respond to unexpected operational incidents. HSE management system includes environmental impact statements, environmental plans, oil spill response and other emergency plans and operational safety cases.
IT resiliency & continuity	The reliance on IT systems, networks and processes continues to evolve, and as the Group grows and develops, the connectivity of networks and systems becomes more complex.  The risk from cyber threats continue to escalate.	Extensive data and server backups are performed regularly.  The Group's redundancy strategy is applied to critical systems and network.  The most up to date security software is maintained, and support and training is provided to all staff to minimize the exposure of security threats.  Network and critical system penetration tests are also performed to measure and assure our level of protection.
Operating performance	The Group is focused on producing assets and discovered resource able to be brought to production rapidly.  In the case of mid-life and/or mature producing assets there is a risk that operational performance will decline through lower production and increased costs.	The Group deploys a midlife field operating philosophy, which closely monitors reservoir, well and plant performance while continuously seeking out operating efficiencies and reinvestment opportunities to increase recovery rates and the production life of each field.  In 2020 Jadestone has implemented a cost saving and efficiency project, Project Clover, to further lower the cost base across all operations and offices.
Pandemic impacts	During 2020, the Group has changed its working practices as offices adapted to working from home and offshore workers had to quarantine between shifts.  While the disruptions have been managed in the short term, any prolonged pandemic related restrictions could impact business performance through a decline in commodity prices and additional expenditure to meet the new working arrangements.	The Group has assessed the financial and operational risks to the business and implemented multiple policies in response to the COVID-19 pandemic.  The Group implemented new procedures covering IT, travel, supply chain and operations.  The Group also implemented recommended safe practices across its operations and offices including remote working guidelines and established pandemic response committees at each location to manage local best practice.
Project execution & economics	As part of the growth strategy, the Group is dependent on the successful execution of strategic projects in Australia, New Zealand, Vietnam and Indonesia.  Project failures could negatively impact operational performance and economic outcomes.	Regular liaison with national oil companies, regulators, and other government bodies to ensure acceptance and approvals are obtained as soon as possible. Projects are tailored to the local market conditions, including with regard to supply and price. Project economics are assessed with multiple sensitives to identify critical challenges, including contingency planning for potential project failures.
Regulatory infringement	The regulatory frameworks across the region within which the Group operates are diverse and complex and include emission controls, operational efficiency, legal and tax regulations, among others. A breach of any aspect could result in loss of production, revenues, increased costs, and/or reputational damage.	Policy and procedures are regularly updated to reflect changes in each of the regulatory environments in which the Group operates. Government relations officers are employed in-country, where it is deemed appropriate, to liaise with government bodies to understand the potential impacts of likely regulatory changes on the business. Regular communications occur with government and trade bodies to understand potential looming and actual changes in the regulatory environment.
Reserve write-downs	The Group is currently dependent on two producing assets and a reserve write down may impact long term business performance and corporate reputation.	The majority of the Group's reserves are in production.  Estimation is done based on actual performance data, reducing the uncertainty range and risk of a write down.  Internal technical reserves reviews ensure a high quality submission.  All assets are either audited or reviewed on an annual basis pursuant to the Group's 51-101 filing requirements.
Sovereign / political risk	The Group's key assets are located in politically stable countries, but there is always the possibility of governmental or regulatory changes which could negatively impact the business.	The Group maintains positive relationships with governments and key stakeholders, and actively monitors the political and regulatory environment within each of the countries and regions in which it operates. Jadestone operates as a good corporate citizen, including in accordance with PSC and tax regulations. New assets are assessed for political risk, and the potential negative impacts that could arise on the Group.

 

 

 

GLOSSARY

 

reserves	hydrocarbon resource that is anticipated to be commercially recovered from known accumulations from a given date forward
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
bbl	barrels
bbls/d	barrels per day
boe	barrels of oil equivalent
bscf	billion standard cubic feet equivalent
capex	capital expenditures
EBITDAX	earnings before interest tax, depreciation, amortisation and exploration
FSO	floating storage and offloading
mm	million
opex	operating expenditures
PSC	production sharing contract

 

 

 

 

CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2020

 

MANAGEMENT'S REPORT

 

The accompanying consolidated financial statements are the responsibility of management.  The consolidated financial statements were prepared by management, in accordance with International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board, and as outlined in the notes to the consolidated financial statements.

 

Management maintains appropriate systems of internal controls.  Policies and procedures are designed to give reasonable assurance that transactions are appropriately authorised, assets are safeguarded, and financial records properly maintained, to provide reliable information for the presentation of consolidated financial statements.

 

Deloitte & Touche LLP, an independent firm of public accountants and chartered accountants, was appointed by the shareholders to audit the consolidated financial statements, and to provide an independent audit opinion.

 

The Audit Committee reviewed the consolidated financial statements with management.  The Board of Directors has approved the consolidated financial statements, on the recommendation of the Audit Committee.

 

These financial statements were approved by the directors and authorised for issue on 22 April 2021.

 

 

 

A. Paul Blakeley							Daniel Young
Director							Director
22 April 2021							22 April 2021

 

    

 

INDEPENDENT AUDITOR'S REPORT

 

TO THE SHAREHOLDERS OF JADESTONE ENERGY INC.

 

Opinion

 

We have audited the accompanying consolidated financial statements of Jadestone Energy Inc. and its subsidiaries (the "Group"), which comprise the consolidated statement of financial position as at 31 December 2020, and the consolidated statement of profit or loss and other comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the year ended 31 December 2020, and notes to the consolidated financial statements, including a summary of significant accounting policies.

 

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Jadestone Energy Inc. as at 31 December 2020, and its financial performance and its cash flows for the year ended 31 December 2020, in accordance with International Financial Reporting Standards ("IFRS"), as issued by International Accountant Standards Board ("IASB").

 

 

Basis for Opinion

 

We conducted our audit in accordance with International Standards on Auditing ("ISAs").  Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audit of the Financial Statements section of our report.  We are independent of the Group in accordance with the International Ethics Standards Board for Accountants' Code of Ethics for Professional Accountants (IESBA Code) together with the ethical requirements that are relevant to our audit of the financial statements in Singapore, and we have fulfilled our other ethical responsibilities in accordance with these requirements.  We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

 

   

 

Key Audit Matters

 

Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the consolidated financial statements of the current year.  These matters were addressed in the context of our audit of the consolidated financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.

 

Key Audit Matters

How the matter was addressed in the audit

Impairment assessment of oil and gas properties As at 31 December 2020, the Group recorded US$317.7 million of oil and gas properties, which approximate 52% of the Group's total assets.   Management performed an assessment of the internal and external factors of the oil and gas properties' carrying values to determine whether there is any indicator of impairment and observed that oil prices decreased significantly in 2020.   Hence, management assessed the recoverability of its oil and gas properties by looking at future cash flows from the respective oil and gas properties ("Financial Model") at 31 December 2020 and its future plans for these assets.  The assessment requires the exercise of significant judgement about and assumptions on, amongst others, the discount rate, oil reserves, expected production volumes and future oil prices.  Accordingly, management who is ultimately responsible for the third party estimates, have also engaged an independent qualified person to estimate, where appropriate, the proved, probable and possible reserves for its oil and gas properties, including the future net cash flows arising from such.   The Group has made disclosures on the above judgement in Note 3.

Our audit procedures focused on evaluating impairment indicators in accordance with IAS 36 Impairment of assets, and challenging the judgements and key assumptions used by management in determining the recoverable amount.  Such procedures included, amongst others:   •      Reviewing the internal and external factors used by management to determine impairment indicators; •      Checking the Group's budget to evaluate the plan for the assets, including the funding options for future capital expenditure to be able to realise the future cash flows; •      Assessing the objectivity, competency and experience of the independent qualified person who prepared the reserve reports; •      Challenging management's oil price assumptions against external data, to determine whether they indicate that there has been a significant change with an adverse effect on the recoverable amount; •      Comparing field and plant production performance during the year against budget, to determine whether they indicate that there has been a significant change with an adverse effect on the recoverable amount; •      Challenging management's assumptions on key data used in their computation of the discount rate; and •      Checking the reserve reports prepared by the independent qualified person to determine that the reserve estimates and expected production volume used by management in its Financial Model is supported.   Based on our procedures, we noted that the carrying amounts of oil and gas properties are stated appropriately.   We have assessed and validated the adequacy and appropriateness of the disclosures made in the financial statements.

 

    

 

Key Audit Matters

How the matter was addressed in the audit

Impairment assessment of intangible exploration assets   As at 31 December 2020, the Group recorded US$100.7 million of intangible exploration assets, which approximate 17% of the Group's total assets.   Management performed an assessment of the internal and external factors of the intangible exploration asset properties' carrying values to determine whether there is any indicator of impairment.   Management also performed an assessment of 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 to commercialise the asset.   Management, who is ultimately responsible for third party estimates, have also engaged an independent qualified person to estimate, where appropriate, the gross contingent resources for all of the intangible exploration assets in previous years and in the current year for the newly acquired Lemang field (Note 15).  Where management has not obtained a revised reserve report, management has assessed that given that these are exploration assets, there are no significant conditions in the current year that will negatively impact reserves.   Based on management's assessment, an impairment loss of US$50.5 million was recorded for the financial year ended 31 December 2020 as detailed in Notes 9 and 16.  Critical judgement and estimates on the above are also disclosed in Note 3.

Our audit procedures focused on evaluating and challenging the judgements and key assumptions used by management in performing the impairment review under IFRS 6 Exploration for and evaluation of mineral resources.  Such procedures included, amongst others:   •      Reviewing the internal and external factors used by management to determine impairment indicators; •      Checking the Group's budget to evaluate the plan for the assets, including the funding options for future capital expenditure to be able to realise the future cash flows; •      Reviewing the relinquishment notification submitted to the relevant authority, where applicable; •      Performing a retrospective review of prior year's work budget and current year's actual activity to determine the reliability of management's plan and budget for the purpose of assessing impairment indicators; •      Assessing the objectivity, competency and experience of the independent qualified person who prepared the reserve reports; and •      Checking the reserve reports prepared by the independent qualified person relating to the Group's estimated reserves, and assessing based on current year activity if there are any negative implications on previously obtained reserve reports.   Based on our procedures, we noted that the carrying amounts of intangible exploration assets are stated appropriately.   We have assessed and validated the adequacy and appropriateness of the disclosures made in the financial statements.

 

  

 

Other Information

 

Management is responsible for the other information. The other information comprises the information, other than the financial statements and our auditor's report thereon, in the Annual Report.

 

Our opinion on the consolidated financial statements does not cover the other information and we do not and will not express any form of assurance conclusion thereon.  In connection with our audit of the consolidated financial statements, our responsibility is to read the other information identified above and, in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements, or our knowledge obtained in the audit, or otherwise appears to be materially misstated.

 

The information, other than the financial statements and the auditors' report thereon, in the Annual Report is expected to be made available to us after the date of this auditor's report.  If, based on the work we will perform on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact to those charged with governance.

 

 

Responsibilities of Management and Those Charged with Governance for the Consolidated Financial Statements

 

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with IFRS, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

 

In preparing the financial statements, management is responsible for assessing the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Group or to cease operations, or has no realistic alternative but to do so.

 

Those charged with governance are responsible for overseeing the Group's financial reporting process.

 

 

 

Auditor's Responsibility for the Audit of the Financial Statements

 

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion.  Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISA will always detect a material misstatement when it exists.  Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements.

 

As part of an audit in accordance with ISA, we exercise professional judgement and maintain professional skepticism throughout the audit.  We also:

 

a)     Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion.  The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.

 

b)    Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group's internal control.

 

c)     Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.

 

d)    Conclude on the appropriateness of management's use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group's ability to continue as a going concern.  If we conclude that a material uncertainty exists, we are required to draw attention in our auditor's report to the related disclosures in the financial statements or, if such disclosures are inadequate, to modify our opinion.  Our conclusions are based on the audit evidence obtained up to the date of our auditor's report.  However, future events or conditions may cause the Group to cease to continue as a going concern.

 

e)    Evaluate the overall presentation, structure and content of the financial statements, including the disclosures, and whether the financial statements represent the underlying transactions and events in a manner that achieves fair presentation.

 

f)     Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the consolidated financial statements.  We are responsible for the direction, supervision and performance of the Group audit.  We remain solely responsible for our audit opinion.

 

 

 

We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

 

We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.

 

From the matters communicated with those charged with governance, we determine those matters that were of most significance in the audit of the financial statements of the current year and are therefore the key audit matters.  We describe these matters in our auditor's report, unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

 

The engagement partner on the audit resulting in this independent auditor's report is Kanagasabai s/o Haridas.

 

 

 

Deloitte & Touche LLP

Public Accountants and

Chartered Accountants

Singapore

 

 

 

22 April 2021

 

 

 

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME FOR THE YEAR ENDED 31 DECEMBER 2020

 

	Notes	2020   USD'000		2019 Reclassified* USD'000
Consolidated statement of profit or loss
Revenue	4	217,938		325,406
Production costs	5	(105,338)		(119,898)
Depletion, depreciation and amortisation	6	(84,642)		(90,746)
Staff costs	7	(21,903)		(22,027)
Other expenses	8	(26,918)		(9,379)
Impairment of assets	9	(50,455)		-
Other income	10	26,376		2,979
Finance costs	11	(12,655)		(16,443)
Other financial gains	12	359		3,389
(Loss)/Profit before tax		(57,238)		73,281
Income tax expense	13	(2,940)		(32,776)
(Loss)/Profit for the year		(60,178)		40,505
(Loss)/Earnings per ordinary share
Basic and diluted (US$)	14	(0.13)		0.09
Consolidated statement of comprehensive income
(Loss)/Profit for the year		(60,178)		40,505
Other comprehensive loss
Items that may be reclassified subsequently to profit or loss:
Gain/(Loss) on unrealised cash flow hedges	27	26,093		(30,542)
Hedging gain reclassified to profit or loss		(31,364)		(14,874)
		(5,271)		(45,416)
Tax income relating to components of other comprehensive   loss	13	1,583		13,624
Other comprehensive loss		(3,688)		(31,792)
Total comprehensive (loss)/income for the year		(63,866)		8,713

 

 

*Certain 2019 comparative information has been reclassified between line items. Please refer to Note 40.

 

All comprehensive (loss)/income is attributable to the equity holders of the parent.

 

The accompanying notes are an integral part of the consolidated financial statements.

 

CONSOLIDATED STATEMENT OF FINANCIAL POSITION AS AT 31 DECEMBER 2020

 

	Notes		2020   USD'000		2019 Reclassified* USD'000
Assets
Non-current assets
Intangible exploration assets	16		100,670		117,440
Oil and gas properties	17		317,676		381,674
Plant and equipment	18		1,652		1,780
Right-of-use assets	19		23,673		59,787
Other receivables	23		4,404		-
Restricted cash	24		-		17,477
Deferred tax assets	21		19,727		16,012
Total non-current assets			467,802		594,170
Current assets
Inventories	22		45,361		31,411
Trade and other receivables	23		7,110		42,283
Derivative financial instruments	34		-		5,275
Restricted cash	24		8,445		6,008
Cash and cash equivalents	24		80,996		75,934
Total current assets			141,912		160,911
Total assets			609,714		755,081
Equity and liabilities
Equity
Capital and reserves
Share capital	25		466,979		466,573
Share-based payments reserve	28		24,985		23,857
Hedging reserves	27		-		3,688
Accumulated losses			(331,322)		(268,651)
Total equity			160,642		225,467
Non-current liabilities
Provisions	29		288,224		280,833
Borrowings	31		-		7,328
Lease liabilities	30		13,305		42,533
Tax liabilities			26,896		-
Deferred tax liabilities	21		58,229		64,825
Total non-current liabilities			386,654		395,519

 

*Certain 2019 comparative information has been reclassified between line items. Please refer to Note 40.
 

 

	Notes		2020   USD'000		2019 Reclassified* USD'000
Current liabilities
Borrowings	31		7,296		41,795
Lease liabilities	30		12,478		19,739
Trade and other payables	33		32,192		25,799
Provisions	29		4,558		2,107
Derivative financial instruments	34		471		-
Tax liabilities			5,423		44,655
Total current liabilities			62,418		134,095
Total liabilities TOTAL EQUITY AND LIABILITIES			449,072		529,614
Total equity and liabilities			609,714		755,081

 

 

 

 

*Certain 2019 comparative information has been reclassified between line items. Please refer to Note 40.

 

The accompanying notes are an integral part of the consolidated financial statements.

 

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY FOR THE YEAR ENDED 31 DECEMEBER 2020

 

	Share capital USD'000		Share-based payments reserve USD'000		Hedging reserves USD'000		Accumulated losses USD'000		Total USD'000
As at 1 January 2019	466,562		22,375		35,480		(309,156)		215,261
Profit for the year	-		-		-		40,505		40,505
Other comprehensive   loss for the year	-		-		(31,792)		-		(31,792)
Total comprehensive   income for the year	-		-		(31,792)		40,505		8,713
Share-based compensation   (Note 7)	-		1,482		-		-		1,482
Shares issued, net of   transaction costs (Note 25)	11		-		-		-		11
Total transactions with   owners, recognised   directly in equity	11		1,482		-		-		1,493
As at 31 December 2019/   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 (Note 26)	-		-		-		(2,493)		(2,493)
Share-based compensation   (Note 7)	-		1,128		-		-		1,128
Shares issued, net of   transaction costs (Note 25)	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

 

 

 

 

The accompanying notes are an integral part of the consolidated financial statements.

 

CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE YEAR ENDED 31 DECEMBER 2020

 

	Notes		2020   USD'000		2019 Reclassified* USD'000
Operating activities
(Loss)/Profit before tax			(57,238)		73,281
Adjustments for:
Depletion, depreciation and amortisation	6		68,414		75,870
Impairment of intangible exploration assets	9		50,455		-
Depreciation of right-of-use assets	6		16,228		14,876
Other finance costs	11		10,289		10,376
Interest expense	11		2,366		6,067
Unrealised foreign exchange loss/(gain)	8 / 10		1,495		(8)
Share-based payments	7		1,128		1,482
Fair value loss on oil derivatives	8		471		-
Inventories written off	8		173		164
Provision of slow moving inventories	8		143		-
Loss on ineffective hedge recycled to profit or loss	8		4		633
Change in Stag FSO provision	10		(5,047)		(1,717)
Gain from termination of right-of-use asset	10		(1,382)		-
Change in fair value of contingent payments	12		(359)		(3,389)
Interest income	10		(257)		(1,260)
Oil and gas properties written off	8		-		533
Operating cash flows before movements in working   capital			86,883		176,908
Decrease/(Increase) in trade and other receivables			35,560		(10,183)
Increase in inventories			(14,071)		(7,510)
Increase/(Decrease) in trade and other payables			3,736		(12,431)
Cash generated from operations			112,108		146,784
Interest paid			(1,542)		(4,698)
Tax (paid)/refunded			(25,969)		2,551
Net cash generated from operating activities			84,597		144,637
Investing activities
Net cash outflows on acquisition of Lemang PSC	15		(11,959)		-
Payment for oil and gas properties	17		(4,732)		(43,817)
Payment for plant and equipment	18		(473)		(502)
Proceeds from disposal of plant and equipment			-		4
Payment for intangible exploration assets	16		(14,253)		(12,933)
Transfer from debt service reserve account	24		5,040		5,159
Interest received	10		257		1,260
Net cash used in investing activities			(26,120)		(50,829)
*Certain 2019 comparative information has been reclassified between line items. Please refer to Note 40.
	Notes		2020   USD'000		2019 Reclassified* USD'000
Financing activities
Net proceeds from issuance of shares	25		406		11
Release of deposit for bank guarantee	24		10,000		-
Dividend paid	26		(2,493)		-
Repayment of borrowings	32		(42,766)		(54,203)
Repayment of lease liabilities	32		(18,562)		(16,671)
Net cash used in financing activities			(53,415)		(70,863)
Net increase in cash and cash equivalents			5,062		22,945
Effect of translation on foreign currency cash and   cash balances			-		8
Cash and cash equivalents at beginning of the year			75,934		52,981
Cash and cash equivalents at end of the year	24		80,996		75,934

 

 

 

 

*Certain 2019 comparative information has been reclassified between line items. Please refer to Note 40.

 

The accompanying notes are an integral part of the consolidated financial statements.

 

SIGNIFICANT ACCOUNTING POLICIES AND EXPLANATION NOTES TO THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2020

 

1.   CORPORATE INFORMATION

 

Jadestone Energy Inc. (the "Company" or "Jadestone") is an oil and gas company incorporated in Canada.

 

As first announced on 1 February 2021, Jadestone is pursuing an internal reorganisation which will result in a new UK-based parent company for the Group, Jadestone Energy plc.  This reorganisation is expected to be effective on 23 April 2021.  The internal reorganisation will not result in a change in control in the ultimate holding company of the Jadestone group of companies and, accordingly, will not result in a change in control in the ultimate shareholding in any of the companies or assets of the Jadestone group of companies.  Further, the internal reorganisation will not result in a change in the management of any of the companies or assets of the Jadestone group of companies.

 

The Company's ordinary shares are listed on AIM, a market by the London Stock Exchange.  The Company was listed on the TSX-V throughout 2019 but delisted on 25 March 2020.  The Company trades under the symbol "JSE".

 

The financial statements are expressed in United States Dollars ("US$" or "USD").

 

The Company and its subsidiaries (the "Group") are engaged in production, development, exploration and appraisal activities in Australia, Vietnam, Indonesia and the Philippines.  The Group's current producing assets are in the Carnarvon (Stag) and Vulcan basins (Montara), offshore Western Australia.  During the year, the Group has submitted a notice to relinquish Service Contract 56 ("SC56") in the Philippines.  The effective date of relinquishment was 21 December 2020.

 

On 29 June 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, onshore Indonesia, for a total cash consideration of US$12.0 million, plus 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 sale and purchase agreement ("SPA").

 

On 16 November 2019, the Group executed a SPA with OMV New Zealand Limited ("OMV New Zealand") to acquire an operated 69% controlling interest in the Maari project for a total consideration of US$50.0 million, and subject to customary working capital adjustments.  The transaction is subject to regulatory approvals and joint venture partners' acceptance.  Following these approvals, the transaction will close and control of the Maari project will transfer to the Group.  The economic benefits from 1 January 2019 until the closing date will be adjusted in the final consideration price.  On 22 March 2021, the Group and OMV New Zealand have agreed to revise the long stop date under the SPA to 30 June 2021.  Both parties remain fully committed to the transaction and anticipate completing the transaction prior to the expiration of the long stop date.

 

The Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower, Singapore 079909.  The registered office of the Company is 10^th Floor, 595 Howe Street, Vancouver, British Columbia V6C 2T5, Canada.  The registered office of the expected new UK-based parent company for the Group, Jadestone Energy plc, is Suite 1, 3rd Floor 11-12 St James's Square, London SW1Y 4LB.

 

 

 

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

BASIS OF PREPARATION

 

The financial statements have been prepared on a going concern basis and in accordance with the historical cost convention basis, except as disclosed in the accounting policies below, and are drawn up in accordance with the provisions of International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board ("IASB").

 

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.

 

Adoption of new and revised standards

New and amended IFRS standards that are effective for the current year

 

Amendments to IFRS 3 Definition of a Business

 

The Group has adopted the amendments to IFRS 3 for the first time in the current year.  The amendments clarify that while businesses usually have outputs, outputs are not required for an integrated set of activities and assets to qualify as a business.  To be considered a business, an acquired set of activities and assets must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create outputs.

 

The amendments remove the assessment of whether market participants are capable of replacing any missing inputs or processes and continuing to produce outputs.  The amendments also introduce additional guidance that helps to determine whether a substantive process has been acquired.

 

 

 

The amendments introduce an optional concentration test that permits a simplified assessment of whether an acquired set of activities and assets is not a business.  Under the optional concentration test, the acquired set of activities and assets is not a business if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar assets.  The amendments are applied prospectively to all business combinations and asset acquisitions for which the acquisition date is on or after 1 January 2020.

 

Amendments to IAS 1 and IAS 8 Definition of Material

 

The Group has adopted the amendments to IAS 1 and IAS 8 for the first time in the current year.  The amendments make the definition of material in IAS 1 easier to understand and are not intended to alter the underlying concept of materiality in IFRS Standards.  The concept of 'obscuring' material information with immaterial information has been included as part of the new definition.

 

The threshold for materiality influencing users has been changed from 'could influence' to 'could reasonably be expected to influence'.  The definition of material in IAS 8 has been replaced by a reference to the definition of material in IAS 1.  In addition, the IASB amended other Standards and the Conceptual Framework that contain a definition of 'material' or refer to the term 'material' to ensure consistency.

 

The adoption of this amendment does not result in changes to the Group's accounting policies and has no material effect on the amounts reported for the current or prior years.

 

Amendments to References to the Conceptual Framework in IFRS Standards

 

The Group has adopted the amendments included in Amendments to References to the Conceptual Framework in IFRS Standards for the first time in the current year.  The amendments include consequential amendments to affected Standards so that they refer to the new Framework.  Not all amendments, however, update those pronouncements with regard to references to and quotes from the Framework so that they refer to the revised Conceptual Framework.  Some pronouncements are only updated to indicate which version of the Framework they are referencing to (the IASC Framework adopted by the IASB in 2001, the IASB Framework of 2010, or the new revised Framework of 2018) or to indicate that definitions in the Standard have not been updated with the new definitions developed in the revised Conceptual Framework.

 

The Standards which are amended are IFRS 2, IFRS 3, IFRS 6, IFRS 14, IAS 1, IAS 8, IAS 34, IAS 37, IAS 38, IFRIC 12, IFRIC 19, IFRIC 20, IFRIC 22, and SIC-32.

 

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 11	Classification of Current or Non-current
Amendments to IFRS 162	COVID-19-Related Rent Concessions
Amendments to IAS 163	Property, Plant and Equipment - Proceeds before Intended Use
Amendments to IFRSs3	Annual Improvements to IFRS Standards 2018 - 2020

 

All amendments are effective for annual periods beginning on or after 1 January 2021 and generally require prospective application.

 

 

 

¹ Effective from 1 January 2023.

² Effective for annual reporting periods beginning on or after 1 June 2020.

³ Effective from 1 January 2022.

 

The Group is currently performing an assessment of the impact of these amendments but does not expect material impact on the financial statements of the Group in future periods, except as noted below:

 

Amendments to IAS 1 Classification of Current or Non-current

 

The amendments to IAS 1 affect only the presentation of liabilities as current or non-current in the statement of financial position and not the amount or timing of recognition of any asset, liability, income or expenses, or the information disclosed about those items.

 

The amendments clarify that the classification of liabilities as current or non-current is based on rights that are in existence at the end of the reporting period, specify that classification is unaffected by expectations about whether an entity will exercise its right to defer settlement of a liability, explain that rights are in existence if covenants are complied with at the end of the reporting period, and introduce a definition of 'settlement' to make clear that settlement refers to the transfer to the counterparty of cash, equity instruments, other assets or services.

 

The amendments are applied retrospectively for annual periods beginning on or after 1 January 2023, with early application permitted.

 

BASIS OF CONSOLIDATION

 

The consolidated financial statements incorporate the financial statements of the Company and enterprises controlled by the Company and its subsidiaries.  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.

 

 

 

 

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.

 

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 re-measured 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 requirements to be treated as a business combination and definition of a business.

 

 

 

 

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 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.

 

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 IFRSs 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 licence, 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.

 

FARM-OUTS IN THE EXPLORATION AND EVALUATION PHASE

 

The Group does not record any expenditure made by the farmee on its account.  It also does not recognise any gain or loss on its exploration and evaluation farm-out arrangements, but re-designates any costs previously capitalised in relation to the whole interest as relating to the partial interest retained.  Any cash consideration received directly from the farmee is credited against costs previously capitalised in relation to the whole interest, with any excess accounted for by the farmor as a gain on disposal.

 

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.

 

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 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.

 

The asset restoration costs are depleted using the units of production method (see above accounting policy).

 

BORROWING COSTS

 

Finance costs of borrowing are allocated to periods over the term of the related debt, at a constant rate on the carrying amount. Borrowing 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 and this includes borrowing costs in relation to exploration activities which are capitalised in intangible exploration assets, as management is of the view that these do not meet the definition of a qualifying asset.

 

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 during the year relates to the Australian Government's JobKeeper Scheme for the Australian offshore and onshore personnel, as part of the Australian Government initiative to provide immediate financial support as a result of COVID-19 pandemic.  There are no future related costs in respect of these grants which were received solely as compensation for costs incurred in the year.  There are no unfulfilled conditions and 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 are offset against the related costs, in either "production costs" (Note 5) or "staff costs" (Note 7).

  

 

 

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.

 

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 ASSETS

 

At the end of each reporting period, the Group reviews the carrying amounts of its assets 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).  Where it is not possible to estimate the recoverable amount of an individual asset, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs.  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 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 less applicable selling expenses.  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 exist.

 

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 and points 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 10) line item.

 

Foreign exchange gains and losses

 

The carrying amount of financial assets that are denominated in a foreign currency is determined in that foreign currency and translated at the spot rate at the end of each reporting period.

 

All financial assets measured at amortised cost that are not part of a designated hedging relationship, exchange differences are recognised in profit or loss in either "other income" (Note 10) or "other expenses" (Note 8) 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 (i) counterparties to oil and gas sales and (ii) governments for recoverable amounts of value added taxes.

 

The concentration of credit risk relates to the main counterparty to oil and gas sales in Australia, where the sole customer has an A1 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 3 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 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 collaterals 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 12) or "finance costs" (Note 11) 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 and points 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.

 

Foreign exchange gains or losses

 

For financial liabilities that are denominated in a foreign currency and are measured at amortised cost at the end of each reporting period, the foreign exchange gains and losses are determined based on the amortised cost of the instruments.  These foreign exchange gains and losses are recognised in the "other income" (Note 10) or "other expenses" (Note 8) line items in profit or loss for financial liabilities that are not part of a designated hedging relationship.  For those which are designated as a hedging instrument for a hedge of foreign currency risk, foreign exchange gains and losses are recognised in other comprehensive income and accumulated in a separate component of equity.

 

Equity instruments

 

Equity instruments issued by the Group are recorded at the fair value of the proceeds received, net of direct issue costs, except where the accounting treatment is defined by a separate accounting standard, as in the case of share-based payments.

 

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 decognised, and the consideration paid and payable, is recognised in profit or loss.

 

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 is subsequently remeasured to fair value as at each reporting date.  The resulting gain or loss is recognised in profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which case the timing of the recognition in profit or loss depends on the nature of the hedge relationship.

 

 

 

A derivative with a positive fair value is recognised as a financial asset whereas a derivative with a negative fair value is recognised as a financial liability.  Derivatives are not offset in the financial statements unless the Group has both a legally enforceable right and intention to offset.  A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than 12 months and it is not due to be realised or settled within 12 months.  Other derivatives are presented as current assets or current liabilities.

 

Hedge accounting

 

All hedges are classified as cash flow hedges, which hedges exposure to the variability in cash flows that is either attributable to a particular risk associated with a recognised asset or liability, or a component of a recognised asset or liability, or a highly probable forecasted transaction.

 

At the inception of the hedge relationship, the Group documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions.  Furthermore, at the inception of the hedge and on an ongoing basis, the Group documents whether the hedging instrument is effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk, which is when the hedging relationships meet all of the following hedge effectiveness requirements:

 

-           there is an economic relationship between the hedged item and the hedging instrument;

 

-           the effect of credit risk does not dominate the value changes that result from that economic relationship; and

 

-           the hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Group actually hedges and the quantity of the hedging instrument that the Group actually uses to hedge that quantity of hedged item.

 

If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio, but the risk management objective for that designated hedging relationship remains the same, the Group adjusts the hedge ratio of the hedging relationship (i.e. rebalances the hedge), so that it meets the qualifying criteria again.

 

The Group designates the full change in the fair value of a forward contract (i.e. including the forward elements) as the hedging instrument, for all of its hedging relationships involving forward contracts.  The Group designates only the intrinsic value of option contracts as a hedged item, i.e. excluding the time value of the option.  The changes in the fair value of the aligned time value of the option are recognised in other comprehensive income and accumulated in the cost of hedging reserve.  If the hedged item is transaction‑related, the time value is reclassified to profit or loss when the hedged item affects profit or loss. If the hedged item is time‑period related, then the amount accumulated in the cost of hedging reserve is reclassified to profit or loss on a rational basis; the Group applies straight‑line amortisation.  Those reclassified amounts are recognised in profit or loss in the same line as the hedged item.  If the hedged item is a non‑financial item, then the amount accumulated in the cost of hedging reserve is removed directly from equity and included in the initial carrying amount of the recognised non‑financial item.  Furthermore, if the Group expects that some or all of the loss accumulated in cost of hedging reserve will not be recovered in the future, that amount is immediately reclassified to profit or loss.

 

Note 34 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 27.

 

 

 

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 12) or "finance costs"
(Note 11) 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.

 

EQUITY INSTRUMENTS

 

Ordinary shares are classified as equity and recorded at the value of consideration received.  The cost of issuing shares is shown in share capital as a deduction, net of tax, from the proceeds.

 

SHARE-BASED PAYMENTS

 

Share-based incentive arrangements are provided to employees, allowing them to acquire shares of the Company.

 

The fair value of options granted is recognised as an employee expense, with a corresponding increase in equity.

 

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, and in the case of non-market related performance conditions, where it becomes unlikely they will vest.  At the end of the reporting period, the Group revises its estimates of the number of equity instruments expected to vest.  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 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 has revalued certain lease liabilities to nil followed by the termination of 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.

 

The 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 stand-alone 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.

 

When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, the receivable is recognised as an asset if it is virtually certain that reimbursement will be received and the amount of the receivable can be measured reliably.

 

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.

 

Production revenue (liquids revenue) is recognised when the Group gives up control of the unit of production at the delivery point agreed under the terms of the 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.

 

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.

 

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. Deferred tax in relation to PRRT is calculated at a rate of 28%.

 

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.

 

Other taxes

 

Revenue, expenses, assets, and liabilities are recognised net of the amount of Goods and Services Tax ("GST") except:

 

-             when the GST incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the GST 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 included.

 

The net amount of GST recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the consolidated statement of financial position.

 

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).

 

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.

 

 

3.   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 following are the critical judgements, apart from those involving estimates (see below), that management has made on the process of applying the Group's accounting policies that have the most significant effect on the amounts recognised in the financial statements.

 

a)      Acquisitions, divestitures, farm-in arrangements and/or assignment of interests

 

The Group accounts for acquisitions, divestitures, and farm-in arrangements 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 Group considers farm-in arrangements that pertain to exploration interests, with no production license, and no proved reserves, to be assets, rather than a business, and would account for such farm-ins based on the consideration paid, which would be capitalised as an intangible exploration asset and subject to impairment reviews.

 

b)      Liquidity and going concern

 

Despite the lower realised prices during 2020, arising from the impact of the COVID-19 pandemic on benchmark crude oil prices, and the resultant impact on revenue, the Group was able to generate positive organic free cashflow in 2020.  The Group manages it liquidity risk by optimising the positive free cash flow from its producing assets, and in 2020 implemented an aggressive and on-going business performance and efficiency programme named Project Clover.  Project Clover aims to identify potential savings as well as area to further improve operational efficiency within the Group's operations, to reinforce its resiliency through the pandemic.  Where possible, the savings achieved under Project Clover will be embedded as structural changes in the Group's future cost base.  In addition, several significant capital expenditure programmes were also deferred, to preserve the Group's cash balance during the low oil price environment.

 

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)      Contingent consideration

 

The determination of the contingent liability components within purchase agreements requires significant management judgement and assumptions.  The contingent payments are based on multiple future triggering events that may or may not occur.  The Group assesses these factors independently, taking into account probabilities and future circumstances.  Where management deems necessary, independent valuation models and advisors will be requested to determine the fair value of such commitments. The contingent consideration payments for the Lemang PSC are set out in Note 15.

 

b)      Depletion of oil and gas properties

 

Oil and gas properties are depleted using the units of production method.

 

Estimates of the Group's oil and gas reserves are inherently uncertain.  Proved plus probable reserves are the estimated volumes of crude oil and natural gas which geological and engineering data demonstrate are most likely to be economically producible, from known reservoirs under existing economic conditions and operating methods.  Changes in proved plus probable oil and gas reserves, and the associated expected development capital, will affect units of production depletion in the Group's consolidated financial statements for oil and gas properties.  Proved plus probable oil and gas reserves are subject to revision, based on new information, such as from development drilling and production activities, or from changes in economic factors, including product prices, contract terms, evolution of technology or development plans, etc.

 

The carrying amount and depletion amount of oil and gas properties are disclosed in Notes 17
and 6, respectively.

 

 

 

c)       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 and PRRT assets requires 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 amounts of the Group's deferred tax assets are disclosed in Note 21 to the financial statements.

 

d)      Reserves estimates

 

The estimated reserves are management assessments, and take into consideration reviews by an independent third party, under the Group's reserves audit programme, as well as other assumptions, interpretations and assessments.  These include assumptions regarding commodity prices, exchange rates, discount rates, future production and 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 values, 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.

 

e)      Impairment of assets

 

The Group undertakes a regular review of asset carrying values 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 assessed its recoverable amount using the value in use approach.  The post-tax estimated future cash flows are prepared based on estimated reserves, future production profiles, future oil prices assumptions and costs.  In view of the low oil price environment arising from the impacts of COVID-19 pandemic, management has revised downward its future oil prices assumptions, compared to assumptions used in prior year.  The future oil price assumptions used are highly judgemental and may be subject to increased uncertainty given the climate change, the global energy transition and the COVID-19 impacts.  There is a risk that management do not forecast reasonable "best estimate" oil prices for the purpose of impairment assessment.

 

For right-of-use assets, 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.

 

The carrying amounts of intangible exploration assets, oil and gas properties and right-of-use assets are disclosed in Notes 16, 17 and 19, respectively.

 

f)       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 29 to the financial statements.

 

g)      Lemang PSC asset acquisition

 

Management has reviewed and assessed that the acquisition of the Lemang PSC does not meet the definition of a business combination according to IFRS 3 Business Combinations. Accordingly, it is classified as an asset acquisition. Management identified and recognised the individual identifiable assets acquired and liabilities assumed and allocated the cost of 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 acquisition. The Group assessed the fair values based on the estimated future economic benefits and costs associated with these assets and liabilities, as at the date of acquisition. The fair value of identifiable assets and liabilities are set out in Note 15.

 

 

4.    REVENUE

 

The Group presently derives its revenue from contracts with customers for the sale of oil products.

 

In line with the revenue accounting policies set out in Note 2, all revenue is recognised at a point in time.

 

		2020 USD'000		2019 USD'000
Liquids revenue, after hedging		217,938		325,406

 

 

5.    PRODUCTION COSTS

		2020 USD'000		2019 USD'000
Operating costs		49,675		52,527
Workovers		21,686		30,331
Logistics		14,333		20,635
Repairs and maintenance		22,450		23,742
Movement in inventories		(2,806)		(7,337)
		105,338		119,898

 

Operating costs in 2020 are net of US$0.6 million received during the year from the Australian Government's JobKeeper scheme in respect of the Group's Australian offshore personnel.

 

 

 

6.    DEPLETION, DEPRECIATION AND AMORTISATION ("DD&A")

		2020 USD'000		2019 USD'000
Depletion and amortisation (Note 17):		68,005		83,686
Depreciation of:
Plant and equipment (Note 18)		601		427
Right-of-use assets (Note 19)		16,228		14,876
Movement in inventories		(192)		(8,243)
		84,642		90,746

 

 

7.    STAFF COSTS

		2020   USD'000		2019 Reclassified USD'000
Wages, salaries and fees		16,721		16,077
Staff benefits in kind		4,054		4,468
Share-based compensation		1,128		1,482
		21,903		22,027

 

The above staff cost includes all directors' salaries and fees.

 

Wages, salaries and fees in 2020 are net of US$0.5 million received during the year from the Australian Government's JobKeeper scheme in respect of the Group's Australian onshore personnel.

 

 

8.    OTHER EXPENSES

		2020   USD'000		2019 Reclassified USD'000
Corporate costs		19,265		7,398
Rig contract deferral costs		3,000		-
Exploration expenses		972		-
Loss on valuation of oil derivatives		475		633
Assets written off		173		697
Provision for slow moving inventories		143		-
Other expenses		2,890		651
		26,918		9,379

 

The increase in corporate costs during the year is predominately due to the litigation costs incurred in relation to the SC56 and 05-1 PSC arbitrations of US$9.1 million, and project transition costs of US$1.0 million.

 

Rig contract deferral costs in Australia of US$3.0 million arose from the decision to defer the Australian 2020 drilling campaign in response to the impact of COVID-19.

 

 

9.    IMPAIRMENT OF ASSETS

		2020 USD'000		2019 USD'000
Impairment of intangible exploration assets (Note 16)		50,455		-

 

The impairment expense of US$50.5 million relates to management's decision to voluntarily relinquish SC56.  During the year Total, the operator of SC56, notified the Group of its intention to withdraw from the block at the end of the current exploration phase.  Having reviewed its options, the Group decided to relinquish its interest in the block with Total, and return the exploration license to the Philippines Department of Energy ("DOE").  The relinquishment notification was submitted on 18 November 2020.  The effective date of relinquishment was 21 December 2020.

 

 

10.  OTHER INCOME

		2020 USD'000		2019 USD'000
Interest income		257		1,260
Litigation income		11,075		-
Fair value gain on foreign exchange derivatives		3,784		-
Reversal/Change in Stag FSO provision		5,047		1,717
Gain from termination of right-of-use asset		1,382		-
Net foreign exchange gain		48		2
Other income		4,783		-
		26,376		2,979

 

Litigation income represents the arbitration award granted in January 2020, in response to a breach of the SC56 farm out agreement by Total E&P Philippines BV.  The breach of the SC56 farm out agreement arose in 2017, at which point the Group commenced arbitration proceedings against Total with the Singapore International Arbitration Centre, claiming failure by Total to drill a commitment well and resultant damages.  On 24 March 2020, the court issued the final award in favour of Jadestone.

 

Other income includes the settlement sum of US$1.0 million agreed by the Group with Teikoku Oil (Con Son) Co. Ltd ("Teikoku"), a subsidiary of Inpex Corporation, in November 2020 to resolve the dispute between both parties in relation to the arbitration proceedings commenced by the Group against Teikoku in July 2020 over Block 05-1 PSC. Other income also includes US$3.6 million of rental income from a helicopter rental contract (a right-of-use asset) to a third party.

 

 

 

11.  FINANCE COSTS

 

		2020 USD'000		2019 USD'000
Interest expense		2,366		6,067
Accretion expense for asset retirement obligations (Note 29)		6,312		5,842
Interest expense on lease liabilities		3,341		4,280
Accretion expense for Stag FSO provision		51		110
Other finance costs		585		144
		12,655		16,443

 

Interest expense refers to the effective interest charge on the reserve based lending facility.

 

 

12.  OTHER FINANCIAL GAINS

 

		2020 USD'000		2019 USD'000
Change in provisions - Montara contingent payments		359		3,389

 

The change in provisions represents the reduction in the fair value of the Montara contingent payments.  The Group has derecognised the 2020 contingent payment as the trigger event to crystallise this payment did not arise.  The fair values of the remaining contingent payments have been valued as US$ Nil, as the possibility of realisation is remote.

 

 

13.  INCOME TAX EXPENSE

		2020 USD'000		2019 USD'000
Current tax
Corporate tax		(11,020)		(43,370)
Petroleum resource rent tax ("PRRT")		(1,678)		1,850
Overprovision in prior year		1,030		-
		(11,668)		(41,520)
Deferred tax
Tax depreciation		4,026		20,285
Tax losses		-		(5,257)
PRRT		4,702		(6,284)
		8,728		8,744
		(2,940)		(32,776)

 

 

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.

 

During the year, Stag recorded a net PRRT credit of US$3.0 million and gained PRRT carried forward credits of US$4.7 million during the year.  In 2019, Stag incurred a net expense of US$4.4 million, after utilised PRRT carried forward credits of US$1.1 million.

 

Montara has utilised PRRT carried forward credits of US$6.4 million during the year with no PRRT expense incurred.  As at year end, Montara has US$3.3 billion (2019: US$3.1 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.

 

The Company was a resident in the Province of British Columbia and paid no Canadian tax; the Group has no operating business in Canada.  Subsidiaries are resident for tax purposes in the territories in which they operate.

 

As first announced on 1 February 2021, the Company is pursuing an internal reorganisation which will result in a new UK-based parent company for the Group, Jadestone Energy plc.  This reorganisation is expected to be effective on 23 April 2021.  The internal reorganisation will not result in a change in control in the ultimate holding company of the Jadestone group of companies and, accordingly, will not result in a change in control in the ultimate shareholding in any of the companies or assets of the Jadestone group of companies.  Further, the internal reorganisation will not result in a change in the management of any of the companies or assets of the Jadestone group of companies.  Jadestone Energy plc is in the process of applying to the UK and Singapore tax authorities to confirm its tax domicile to be Singapore.

 

The tax expense on Group's (loss)/profit differs from the amount that would arise using the standard rate of income tax applicable in the countries of operation as explained below:

 

		2020 USD'000		2019 USD'000
(Loss)/Profit before tax		(57,238)		73,281
Tax calculated at the domestic tax rates applicable to the profit/loss   in the respective countries (Australia 30%, New Zealand 28%,     Canada 27% and Singapore 17%)		9,198		(23,190)
Effects of non-deductible expenses		(16,192)		(5,152)
Effect of PRRT tax (expense)/benefit		(1,678)		1,850
Deferred PRRT tax credit/(expense)		4,702		(6,284)
Overprovision in prior year		1,030		-
Tax expense for the year		(2,940)		(32,776)

 

 

 

In addition to the amount charged to the profit or loss, the following amounts relating to tax have been recognised in other comprehensive income.

 

		2020 USD'000		2019 USD'000
Other comprehensive loss - deferred tax
Income tax credit related to carrying amount of hedged item		(1,583)		(13,624)

 

 

14.  (LOSS)/EARNINGS PER ORDINARY SHARE

 

The calculation of the basic and diluted (loss)/profit per share is based on the following data:

 

		2020 USD'000		2019 USD'000
(Loss)/Profit for the purposes of basic and diluted per share, being the net (loss)/profit for the year attributable to equity holders of   the Company		(60,178)		40,505
		2020 Number		2019 Number
Weighted average number of ordinary shares for the purposes of   basic EPS		463,553,521		461,040,802
Effect of diluted potential ordinary shares - share options		-		2,512,719
Weighted average number of ordinary shares for the purposes of   dilutive EPS		463,553,521		463,553,521

 

In 2020, 4,679,402 of potential ordinary shares associated with share options are anti-dilutive.

 

The calculation of diluted EPS for 2019 includes 2,512,719 of weighted average dilutive ordinary shares available for exercise from in-the-money vested options.  Additionally, 590,902 of weighted average potential ordinary shares available for exercise in 2020 are excluded, as they are out-of-the-money (2019: 607,821).

 

(Loss)/Earnings per share (US$)		2020		2019
-       - Basic and diluted		(0.13)		0.09

 

 

 

 

15.  ACQUISITION OF LEMANG PSC

 

15.1 Acquisition date

 

On 29 June 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.  These included the receipt of governmental approval of the assignment of the interest and of the Group's appointment as operator, and other consents required under the Lemang PSC joint operating agreement.

 

15.2 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 Business Combinations.  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.

 

15.3 Fair value of consideration transferred

 

The fair value consideration of the Lemang PSC reflected a 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 outlfows 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 15.5 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.

 

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.

 

15.4 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:

 

	Total USD'000
Asset
Non-current assets
Intangible exploration assets (Note 16)	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 29)	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 the oil production by Mandala Energy that has ceased at the Lemang PSC prior to the acquisition.  This liability is assumed by the Group following the acquisition.  The decommissioning expenditure is expected to be incurred from 2034, at the end of the life of the gas asset.

 

15.5 Deferred contingent consideration

 

No.	Trigger event	Consideration	Management's rationale
1.	First gas date	US$5.0 million	Please refer to 15.3 above.
2.	The accumulated VAT receivables reimbursements which are attributable to the unbilled VAT in the Lemang Block as at the Closing Date, exceeding an aggregate amount of US$6.7 million on a gross basis	US$0.7 million	Please refer to 15.3 above.
3.	First gas date on or before 31 March 2023	US$3.0 million	It is unlikely that the first gas date will be on or before 31 March 2023.
4.	Total actual Akatara Gas Project "close out" costs set out in the AFE(s) approved pursuant to a joint audit by SKK MIGAS and BPKP is less than, or within 2% of the "close out" development costs set out in the approved revised plan of development for the Akatara Gas Project	US$3.0 million	The Akatara Gas Project has not been sanctioned as at year end due to ongoing preparation of project approval documentation.  It is unknown if the future close out costs will be less than or within 2% of the budgeted amount and it is unable to be reliably measured as at year end.
No.	Trigger event	Consideration	Management's rationale
5.	The average Saudi CP in the first year of operation is higher than US$620/MT	US$3.0 million	Saudi CP is not expected to be above US$620/MT throughout the PSC term to 2037.
6.	The average Saudi CP in the second year of operation is higher than US$620/MT	US$2.0 million	Saudi CP is not expected to be above US$620/MT throughout the PSC term to 2037.
7.	The average Dated Brent price in the first year of operation is higher than US$80/bbl	US$2.5 million	The Dated Brent price is not expected to be above US$80/bbl throughout the PSC term to 2037.
8.	The average Dated Brent price in the second year of operation is higher than US$80/bbl	US$1.5 million	The Dated Brent price is not expected to be above US$80/bbl throughout the PSC term to 2037.
9.	A plan of development for the development of a new discovery made, as a result of the remaining exploration well commitment under the PSC, is approved by the relevant government entity.	US$3.0 million	There are no prospects or leads presently selected for the exploration well commitment.  As at year end, it is not probable that this contingent consideration trigger will be met.
10.	The plan of development described in item 9 above is approved by the relevant government entity and is based on reserves of no less than 8.4mm barrels (on a gross basis).	US$8.0 million	There are no prospects or leads presently selected for the exploration well commitment.  As at year end, it is not probable that this contingent consideration trigger will be met.

 

 

16.  INTANGIBLE EXPLORATION ASSETS

	Total USD'000
Cost
As at 1 January 2019	95,607
Additions	21,833
As at 31 December 2019/1 January 2020 (Reclassified)	117,440
Acquisition of Lemang PSC (Note 15)	14,825
Additions	18,860
As at 31 December 2020	151,125
	Total USD'000
Impairments
As at 1 January 2019/31 December 2019/1 January 2020	-
Additions (Note 9)	50,455
As at 31 December 2020	50,455
Net book value
As at 31 December 2019 (Reclassified)	117,440
As at 31 December 2020	100,670

 

For the purpose of the consolidated statement of cash flows, current year expenditure on intangible exploration assets of US$4.6 million remained unpaid as at 31 December 2020 (2019: US$8.9 million).

 

 

17.  OIL AND GAS PROPERTIES

	Total USD'000
Cost
As at 1 January 2019	457,818
Changes in asset restoration obligations (Note 29)	(8,117)
Additions	43,817
Written off	(533)
As at 31 December 2019/1 January 2020 (Reclassified)	492,985
Changes in asset restoration obligations (Note 29)	(725)
Additions	4,732
As at 31 December 2020	496,992
Accumulated depletion and amortisation
As at 1 January 2019	27,625
Charge for the year	83,686
As at 31 December 2019/1 January 2020	111,311
Charge for the year	68,005
As at 31 December 2020	179,316
Net book value
As at 31 December 2019 (Reclassified)	381,674
As at 31 December 2020	317,676

 

18.  PLANT AND EQUIPMENT

	Computer equipment USD'000		Fixtures and fittings USD'000		Total USD'000
Cost
As at 1 January 2019	2,372		1,269		3,641
Additions	452		50		502
Disposal	-		(4)		(4)
As at 31 December 2019/1 January 2020	2,824		1,315		4,139
Additions	280		193		473
As at 31 December 2020	3,104		1,508		4,612
Accumulated depreciation
As at 1 January 2019	975		957		1,932
Charge for the year	359		68		427
Disposal	-		-*		-*
As at 31 December 2019/1 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
Net book value
As at 31 December 2019	1,490		290		1,780
As at 31 December 2020	1,447		205		1,652

 

*Due to figures rounded to nearest thousand.

 

 

 

19.  RIGHT-OF-USE ASSETS

 

	Production assets USD'000		Transportation and logistics USD'000		Buildings USD'000		Total USD'000
Cost
As at 1 January 2019	29,339		3,507		3,004		35,850
Additions	-		38,813		-		38,813
As at 31 December 2019/    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
Accumulated depreciation
As at 1 January 2019	-		-		-		-
Charge for the year	5,334		8,519		1,023		14,876
As at 31 December 2019/   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
Net book value
As at 31 December 2019	24,005		33,801		1,981		59,787
As at 31 December 2020	-		22,407		1,266		23,673

The decrease in production assets arose from the termination of the Stag FSO lease in September 2020, due to the retirement of the FSO by its owner, and the Group's move to the shuttle tank model.

 

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 30.

 

	2020 USD'000		2019 USD'000
Amount recognised in profit or loss
Depreciation expense on right-of-use assets	16,228		14,876
Interest expense on lease liabilities	3,341		4,280
Expenses relating to short-term leases	3,065		11,748
Expense relating to leases of low value assets	30		15

 

 

 

 

20.  INVESTMENTS IN SUBSIDIARIES AND INTERESTS IN JOINT OPERATIONS

 

The succeeding sections of this Note present the details of the principal subsidiaries and joint operations of the Group.

 

Details of the investments in which the Group holds 20% or more of the nominal value of any class of share capital are as follows:

 

Name of the company	Place of incorporation	% voting rights and shares held 2020	% voting rights and shares held 2019	Nature of business
Jadestone Energy (Eagle) Pty Ltd	Australia	100	100	Production oil &   gas
Jadestone Energy (Australia   Holdings) Pty Ltd	Australia	100	100	Investment   holdings
Jadestone Energy (Australia) Pty Ltd	Australia	100	100	Production oil &   gas
Jadestone Energy (New Zealand   Holdings) Ltd	New Zealand	100	100	Investment   holdings
Jadestone Energy (New Zealand)   Ltd	New Zealand	100	100	Production oil &   gas
Jadestone Energy (Lemang) Pte Ltd	Singapore	100	-*	Exploration
Jadestone Energy (Singapore) Pte Ltd	Singapore	100	100	Investment   holdings
Jadestone Energy International   Holdings Inc.	Canada	100	100	Investment   holdings
Jadestone Energy Ltd	Bermuda	100	100	Investment   holdings
Jadestone Energy Sdn Bhd	Malaysia	100	100	Administration
Mitra Energy (Philippines SC- 56) Ltd	Bermuda	100	100	Exploration
Mitra Energy (Philippines SC- 57) Ltd	BVI	100	100	Exploration
Mitra Energy (Vietnam 05-1) Pte Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Nam Du) Pte   Ltd	Singapore	100	100	Exploration
Mitra Energy (Vietnam Tho Chu) Pte   Ltd	Singapore	100	100	Exploration

* Jadestone Energy (Lemang) Pte Ltd was incorporated on 19 June 2020 as part of the Lemang PSC acquisition.

 

 

 

 

Details of the operations, of which all are in exploration stage except for Stag and Montara which are in the production stage, are as follows:

 

				Group effective working interest % as at 31 December
Contract Area	Date of expiry	Held by	Place of operations	2020	2019
Montara   Oilfield	Indefinite	Jadestone Energy (Eagle) Pty Ltd	Australia	100	100
Stag Oilfield	25 Aug 2039	Jadestone Energy (Australia) Pty Ltd	Australia	100	100
46/07	29 Jun 2035	Mitra Energy (Vietnam Nam Du) Pte   Ltd	Vietnam	100	100
51	10 Jun 2040	Mitra Energy (Vietnam Tho Chu) Pte   Ltd	Vietnam	100	100
Lemang	17 Jan 2037	Jadestone Energy (Lemang) Pte Ltd	Indonesia	90	-
SC57	14 Sept 2055	Mitra Energy (Philippines SC-57) Ltd	Philippines	21	21
SC56	4 Aug 2055	Mitra Energy (Philippines SC-56) Ltd	Philippines	-	25

 

21.  DEFERRED TAX

 

The following are the deferred tax liabilities and assets recognised by the Group and movements thereon.

 

	Australian PRRT USD'000		Tax depreciation USD'000		Derivatives financial instruments USD'000		Tax losses USD'000		Total USD'000
As at 1 January 2019	19,499		(80,730)		(15,207)		5,257		(71,181)
(Charged)/Credited to   profit or loss	(6,284)		20,285		-		(5,257)		8,744
Credited to OCI	-		-		13,624		-		13,624
As at 31 December   2019/1 January 2020	13,215		(60,445)		(1,583)		-		(48,813)
Credited to profit or   loss	4,702		4,026		-		-		8,728
Credited to OCI	-		-		1,583		-		1,583
As at 31 December   2020	17,917		(56,419)		-		-		(38,502)

 

 

 

 

The following is the analysis of the deferred tax balances (after offset) for financial reporting purposes:

 

		2020 USD'000		2019 USD'000
Deferred tax liabilities		(58,229)		(64,825)
Deferred tax assets		19,727		16,012
		(38,502)		(48,813)

 

The Group has unutilised PRRT credits of approximately US$3.3 billion (2019: US$3.1 billion) available for offset against future PRRT taxable profits in respect of the Montara field.  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$3.3 billion (2019: US$3.1 billion) will not be utilised given the forecasted augmentation, and are therefore not recognised as a deferred tax asset.

 

 

22.  INVENTORIES

 

		2020 USD'000		2019 USD'000
Materials and spares		20,059		8,964
Less: provision for slow moving (Note 8)		(143)		-
		19,916		8,964
Crude oil inventories		25,445		22,447
		45,361		31,411

 

The cost of inventories recognised as an expense during the year for lifted volumes, comprising production costs excluding workovers, plus depletion expense of oil & gas properties, and plus depreciation of right-of-use assets deployed for operational use, is US$166.9 million (2019: US$187.1 million).

 

 

 

 

23.  TRADE AND OTHER RECEIVABLES

 

		2020 USD'000		2019 USD'000
Current assets
Trade receivables		106		34,007
Prepayments		2,012		4,754
Other receivables and deposits		4,273		2,311
GST/VAT receivables		719		1,211
		7,110		42,283
Non-current asset
VAT receivables		4,404		-
		11,514		42,283

 

Trade receivables arise from revenues generated in Australia.  The average credit period is 30 days (2019: 30 days).  All outstanding receivables as at 31 December 2020 and 2019 have been fully recovered in 2021 and 2020, respectively.

 

The non-current VAT receivables of US$4.4 million 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 2021.

 

No interest is charged on outstanding receivables.  There are no trade receivables older than 30 days.

 

 

24.  CASH AND BANK BALANCES

		2020 USD'000		2019 USD'000
Current assets
Cash and bank balances		89,441		81,942
Less: restricted cash		(8,445)		(6,008)
Cash and cash equivalents		80,996		75,934
Non-current assets
Cash and bank balances		-		17,477
Less: restricted cash		-		(17,477)
Cash and cash equivalents		-		-
Cash and cash equivalents in the consolidated statement of cash   flows		80,996		75,934

 

 

 

As part of the reserve based lending agreement (Note 31), 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").  An amount of US$7.4 million (2019: US$13.5 million) is deposited in the DSRA as at 31 December 2020.  In addition, the Group is required to maintain a minimum cash balance in the Montara cash operating account of US$15.0 million (2019: US$15.0 million).  The DSRA has been classified as restricted cash, given certain restrictions under the loan agreement to withdraw amounts from the DSRA.  The DSRA was released on 31 March 2021, upon the repayment of the final balance outstanding on the loan, and is hence classified as a current asset as at 31 December 2020.

 

On 24 July 2020, the Group entered into a joint study agreement ("JSA") in Indonesia to assess an area in advance of applying for a new PSC.  The JSA required a US$1.0 million performance bank guarantee to be placed with the Indonesian regulator.  It is kept in a specific bank account that has in place restrictions and does not allow for the cash to be used for normal operations.  The bank guarantee will be released to the Group at the completion of the JSA, which is anticipated in Q3 2021.

 

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, has been released to the Group upon the termination of the FSO vessel lease agreement during the year.

 

 

25.  SHARE CAPITAL

 

Authorised ordinary shares

 

Unlimited number of ordinary voting shares with no par value.

 

		No. of shares		USD'000
Issued and fully paid
As at 1 January 2019		461,009,478		466,562
Issued during the year		33,333		11
As at 31 December 2019/1 January 2020		461,042,811		466,573
Issued during the year		800,000		406
As at 31 December 2020		461,842,811		466,979

 

During the year, employee share options of 800,000 were exercised and issued at an average price of GB£ 0.33 per share (2019: 33,333; CAD0.47 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.

 

 

26.  DIVIDENDS

 

An interim dividend of 0.54 US cents/share was declared on 10 September 2020 (0.42 GB pence/share, based on the spot exchange rate of 0.7708 on 9 September 2020) and paid on 30 October 2020, equivalent to a total distribution of US$2.5 million (2019 interim dividend: nil).

 

 

 

27.  HEDGING RESERVES

	2020 USD'000		2019 USD'000
At beginning of the year	(3,688)		(35,480)
(Gain)/Loss arising on changes in fair value of hedging instruments   during the year	(26,093)		30,542
Income tax related to gain/(loss) recognised in other comprehensive   income	7,828		(9,162)
Net gain reclassified to profit or loss	31,364		14,874
Income tax related to amounts reclassified to profit or loss	(9,411)		(4,462)
At end of the year	-		(3,688)

 

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.

 

 

28.  SHARE-BASED PAYMENTS RESERVE

 

The total expense arising from share-based payments recognised for the year ended 31 December 2020 was US$1.1 million (2019: US$1.5 million) (Note 7).

 

On 15 May 2019, the Company adopted, as approved by 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 Common 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.

 

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
	27 April 2020	3 December 2019	28 March 2019
Risk-free rate	1.41% to 1.56%	1.46% to 1.47%	1.46% to 1.47%
Expected life	5.5 to 6.5 years	5.5 to 6.5 years	5.5 to 6.5 years
Expected volatility	42.7% to 43.9%	40.1% to 42.8%	39.9% to 42.3%
Share price	GB£ 0.44	C$1.17	C$0.85
Exercise price	GB£ 0.44	C$1.17	C$0.85
Expected dividends	2.9%	Nil	Nil

 

 

 

 

The following table summarises the share options outstanding and exercisable as at 31 December 2020:

 

	Share Options
	Number of options	Weighted average exercise price C$	Weighted average remaining contract life	Number  of options exercisable
As at 1 January 2019	12,132,842	0.56	8.50	3,232,830
New share options issued	8,075,000	0.85	9.25	75,000
Vested during the year	-	0.50	7.63	3,858,316
Exercised during the year	(33,333)	0.47	-	(33,333)
Cancelled during the year	(306,667)	0.48	-	(113,333)
As at 31 December 2019	19,867,842	0.68	8.21	7,019,480

 

	Share Options
	Number of options	Weighted average exercise price GB£	Weighted average remaining contract life	Number  of options exercisable
As at 1 January 2020	19,867,842	0.39	8.21	7,019,480
New share options issued	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	(400,000)	0.73	-	(200,000)
As at 31 December 2020	25,192,842	0.40	7.91	12,212,827

 

 

 

 

29.  PROVISIONS

		Asset restoration obligations (a) USD'000		Stag FSO (b) USD'000		Contingent payment (c) USD'000		Employees benefit (d) USD'000		Incentive scheme (e) USD'000		Others USD'000		Total USD'000
As at 1 January   2019		277,697		6,603		3,748		762		828		-		289,638
Additions		-		-		-		89		800		-		889
Accretion   expense   (Note 11)		5,842		110		-		-		-		-		5,952
Changes in   discount rate   assumptions   and estimates     (Note 17/   Note 10)		(8,117)		(1,717)		-		-		-		-		(9,834)
Fair value        adjustment     (Note 12)		-		-		(3,389)		-		-		-		(3,389)
Reversal		-		-		-		-		(316)		-		(316)
As at   31 December   2019/ 1   January 2020   (Reclassified)		275,422		4,996		359		851		1,312		-		282,940
Additions		-		-		-		67		1,304		1,905		3,276
Acquisition of   Lemang PSC   (Note 15)		2,741		-		4,436		-		-		-		7,177
Accretion   expense   (Note 11)		6,312		51		-		-		-		-		6,363
Changes in   discount rate   assumptions   (Note 17)		(725)		-		-		-		-		-		(725)
Utilised		-		-		-		(22)		(821)		-		(843)
Fair value        adjustment   (Note 12)		-		-		(359)		-		-		-		(359)
Reversal   (Note 10)		-		(5,047)		-		-		-		-		(5,047)
As at   31 December   2020		283,750		-		4,436		896		1,795		1,905		292,782

 

 

		Asset restoration obligations (a) USD'000		Stag FSO (b) USD'000		Contingent payment (c) USD'000		Employees benefit (d) USD'000		Incentive scheme (e) USD'000		Others USD'000		Total USD'000
As at   31 December   2019   (Reclassified)
Current		-		-		-		795		1,312		-		2,107
Non-current		275,422		4,996		359		56		-		-		280,833
		275,422		4,996		359		851		1,312		-		282,940
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

 

^(a)         The Group's asset restoration obligations ("ARO") comprise the future estimated costs to decommission each of the Montara, Stag and Lemang 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 and Lemang assets have been escalated to the estimated date at which the expenditure would be incurred, at an assumed blended inflation rate of 1.52%, 1.48% and 2.54% respectively (2019: Montara - 2.10%; Stag - 2.06%).  The estimates for Montara and Stag are a blend of assumed US and Australian inflation rates to reflect the underlying mix of US dollar and Australian dollar denominated expenditures.  The estimates for Lemang are a blend of assumed US and Indonesian inflation rates to reflect the underlying mix of US dollar and Indonesian Rupiah denominated expenditures.  The present value of the future estimated ARO for each of the Montara, Stag and Lemang assets has then been calculated based on blended risk-free rates of 1.72%, 1.78% and 5.86% respectively (2019: Montara: 2.31%; Stag - 2.24%).  The base estimate ARO for Montara and Stag remains largely unchanged from 2019.  The Lemang asset ARO was assessed in 2020, based on the existing oil infrastructure assets acquired and required to be decommissioned at the end of field life.

 

Management expects decommissioning expenditures to be incurred from 2031, 2035 and 2034 onwards for Montara, Stag and Lemang, 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.

 

^(b)         The provision for Stag FSO in 2019 represented the fair value of amounts payable to the crew of the FSO on termination of the lease.  The provision has been reversed due to the September 2020 termination of the FSO vessel lease.

 

^(c)        The contingent payment of US$0.4 million in 2019 represented the fair value of 2020 contingent payments to PTTEP for the Montara acquisition.  The 2020 contingent payment has been derecognised during the year as the liability has failed to materialise.  The Group has not recognised other contingent payments as the management considers the probability of outflow is remote.

 

During the year, the Group has recognised contingent consideration payments of US$4.4 million, representing the fair value of contingent payments to Mandala Energy Lemang Pte Ltd for the acquisition of the Lemang PSC (see Note 15.5).

 

^(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 the employees at variable percentages of their annual wage.

 

 

30.  LEASE LIABILITIES

 

		2020 USD'000		2019 USD'000
Presented as:
Non-current		13,305		42,533
Current		12,478		19,739
		25,783		62,272
Maturity analysis of lease liabilities based on undiscounted gross cash   flows:
Year 1		13,448		20,228
Year 2		11,239		19,881
Year 3		2,803		17,934
Year 4		-		9,547
Year 5		-		3,145
Future interest charge		(1,707)		(8,463)
		25,783		62,272

 

The decrease in lease liabilities is predominately due to the termination of the Stag FSO lease in September 2020, due to the retirement of the FSO by its owner, and the resultant move to the shuttle tanker model.

 

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.

 

 

 

31.  BORROWINGS

		2020 USD'000		2019 USD'000
Non-current secured borrowings
Reserve based lending facility		-		7,328
Current secured borrowings
Reserve based lending facility		7,296		41,795
		7,296		49,123

 

During the year, the Group made principal repayment and interest service costs of US$42.8 million and US$1.4 million (2019: US$52.9 million; US$4.5 million) respectively, leaving an outstanding balance of US$7.3 million (2019: US$49.1 million) as at year end, which was repaid in full on 31 March 2021.

 

The loan incurred interest at LIBOR plus 3% (2019: LIBOR plus 3%).

 

 

32.  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		Other Borrowings USD'000
As at 1 January 2019	100,534		-		1,279
Adoption of IFRS 16	-		35,850		-
Financing cash flows	(52,924)		(16,671)		(1,279)
New lease liabilities	-		38,813		-
Interest expense	(4,519)		-		-
Non-cash changes - other changes	6,032		4,280		-
As at 31 December 2019/1 January 2020	49,123		62,272		-
Financing cash flows	(42,766)		(18,562)		-
New lease liabilities	-		891		-
Termination of leases	-		(20,777)
Interest expense	(1,427)		-		-
Non-cash changes - other changes	2,366		1,959		-
As at 31 December 2020	7,296		25,783		-

 

 

 

 

33.  TRADE AND OTHER PAYABLES

		2020   USD'000		2019 (Reclassified) USD'000
Trade payables		10,131		9,192
Other payables		2,004		156
Accruals		20,047		16,347
GST/VAT payables		10		104
		32,192		25,799

 

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 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 Group believes that the carrying amount of trade and other payables approximates their fair value.

 

34.  DERIVATIVE FINANCIAL INSTRUMENTS

 

The Group uses derivatives to manage its exposure to oil price fluctuations.  Oil hedges are undertaken using swaps and, 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").

 

		2020 USD'000		2019 USD'000
Derivative financial assets
Designated as cash flow hedges
Commodity capped swap		-		5,275
Derivative financial liabilities
Carried at FVTPL
Commodity swap		(471)		-

 

 

 

 

The following is a summary of the Group's outstanding derivative contracts:

Contract quantity	Type of contracts	Terms	Contract price	Hedge classification	Fair value asset at 31 December 2020 USD'000	Fair value asset at 31 December 2019 USD'000
Contracts designated as cash flow hedges
27% (2019: 32%) of Group's actual 2PD production	Commodity capped swap: swap component	Oct 2018 -   Sep 2020	US$78.26/bbl for Q4 2018, US$71.72/bbl for 2019 and US$68.45/bbl for the nine months to 30 September  2020	Cash flow	-	5,203
67% of swapped barrels in 2019 and in the nine months to 30 September 2020	Commodity capped swap: call component	Jan 2019 -   Sep 2020	US$80.00/bbl for the nine months to 30 September 2019, then US$85.00/bbl to September 2020		-	72
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 are 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 will systematically change in opposite directions in response to movements in the underlying commodity prices.

 

There is 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 arising from the hedge ineffectiveness amounted to a net loss of approximately US$4,000 in 2020 (2019: US$0.6 million), and has been included in the statement of profit or loss within "other expenses" (Note 8).

 

The following tables detail the commodity swap contracts outstanding at the end of the year, as well as information regarding their related hedged items.  Commodity swap contract assets are included in the "derivative financial instruments" line item in the consolidated statement of financial position.

 

 

 

 

Hedging instruments - outstanding contracts

 

	Oil volumes bbls	Notional value USD'000	Change in fair value used for calculating hedge ineffectiveness USD'000	Fair value USD'000
2019
Cash flow hedges
Commodity swap component	1,136,940	77,829	633	5,203
Commodity call component	568,470	48,320	-	72
			633	5,275

Hedged items

 

	Change in value used for calculating hedge ineffectiveness USD'000	Balance in cash flow hedge reserve for continuing hedges USD'000	Balance in cash flow hedge reserve arising from hedging relationships for which hedge accounting is no longer applied USD'000
2020
Cash flow hedges
Forecast sales	4	-	-
2019
Cash flow hedges
Forecast sales	633	3,688	-

The following table details the effectiveness of the hedging relationships and the amounts reclassified from hedging reserve to profit or loss:

 

	Current period hedging gain/(loss) recognised in OCI USD'000	Amount of hedge ineffectiveness recognised in profit or loss USD'000	Line item in profit or loss in which hedge ineffectiveness is included	Amount reclassified to profit or loss due to hedged item affecting profit or loss USD'000	Line item in profit or loss in which reclassification adjustment is included
2020
Cash flow hedges
Forecast sales	18,265	4	Other expenses	31,360	Revenue
2019
Cash flow hedges
Forecast sales	(21,380)	633	Other expenses	14,241	Revenue

 

 

35.  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 values equate to their fair value.

 

Non-current assets and liabilities

All non-current assets and liabilities are reflected at fair value.

 

		2020 USD'000		2019 USD'000
Financial assets
At amortised cost		93,820		135,737
Derivative instruments designated in hedge accounting relationships		-		5,275
		93,820		141,012
Financial liabilities
At amortised cost		353,607		419,671
Contingent consideration for Montara business acquisition		-		359
Contingent consideration for Lemang PSC acquisition		4,436		-
Derivative instruments carried at FVTPL		471		-
		358,514		420,030

 

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 if 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 have 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 cover 31% of its planned production volumes from January to March 2021, to provide downside price protection.  The swap price was set at US$49/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 forecasters' estimates.

 

Gain or loss	Effect on the result before tax for the year ended 31 December 2020 USD'000	Effect on other comprehensive income before tax for the year ended 31 December 2020 USD'000	Effect on the result before tax for the year ended 31 December 2019 USD'000	Effect on other comprehensive income before tax for the year ended 31 December 2019 USD'000
Increase by 10%	(1,348)	-	-	(7,266)
Decrease by 10%	1,348	-	-	7,266

 

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.  The Group's US$120.0 million reserve based loan facility was a US Dollar denominated instrument.

 

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, Singapore Dollar, Vietnamese Dong, Malaysian Ringgit, Indonesian Rupiah, New Zealand Dollar, British Pound Sterling and Canadian Dollar.

 

 

 

Foreign currency sensitivity

 

Material foreign denominated balances were as follows:

 

		2020 USD'000		2019 USD'000
Cash and bank balances
Australian Dollars		8,043		7,088
Trade and other receivables
Australian Dollars		1,547		5,853
Trade and other payables
Australian Dollars		21,233		16,236
Provisions
Australian Dollars		2,692		7,158

 

A  strengthening/weakening of the Australian dollar 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$1.4 million (2019: US$1.0 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 and borrowings.  The Group's other financial instruments are non-interest bearing or fixed rate, and are therefore not subject to interest rate risk.

 

Jadestone holds some of its cash in interest bearing accounts and short-term deposits.  Interest rates currently received are relatively low levels historically.  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 (2019: US$0.1 million).  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: 

 

Category	Description	Basis for recognising expected credit losses ("ECL")
Performing	The counterparty has a low risk of default and does not have any past-due amounts.	12-month ECL
Doubtful	Amount is > 30 days past due or there has been a significant increase in credit risk since initial recognition.	Lifetime ECL - not credit-impaired
In default	Amount is > 90 days past due or there is evidence indicating the asset is credit-impaired.	Lifetime ECL - credit-impaired
Write-off	There is evidence indicating that the debtor is in severe financial difficulty and the Group has no realistic prospect of recovery.	Amount is written off

 

The table below details the credit quality of the Group's financial assets and other items, as well as maximum exposure to credit risk by credit risk rating grades:

 

		External credit	Internal credit	12-month ("12m") or	Gross carrying amount (i)	Loss allowance	Net carrying amount
	Note	rating	rating	lifetime ECL	USD'000	USD'000	USD'000
2020
Cash and bank   balances	24	n.a	Performing	12m ECL	89,441	-	89,441
Trade receivables	23	n.a	(i)	Lifetime ECL	106	-	106
Other receivables	23	n.a	Performing	12m ECL	4,273	-	4,273
2019
Cash and bank   balances	24	n.a	Performing	12m ECL	99,419	-	99,419
Trade receivables	23	n.a	(i)	Lifetime ECL	34,007	-	34,007
Other receivables	23	n.a	Performing	12m ECL	2,311	-	2,311

 

(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 2020, total trade receivables amounted to US$0.1 million (2019: US$34.0 million).  The balance in 2020 and 2019 had been fully recovered in 2021 and 2020, respectively.

 

 

The concentration of credit risk relates to the main counterparty to oil sales in Australia, where the sole customer has an A1 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 three days of 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 and other receivables are expected to be insignificant.

 

Cash and bank balances are placed with reputable banks and financial institutions, which are regulated, 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 it 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$60.2 million (2019: profit after tax of US$40.5 million), and inclusive of the non-cash SC56 impairment of US$50.4 million (2019: nil).  Operating cash flows before movements in working capital and net cash generated from operating activities for the year ended 31 December 2020 was US$86.9 million and US$84.6 million (2019: US$176.7 million and US$144.6 million) respectively.  The Group's net current assets remained positive at US$79.5 million as at 31 December 2020 (2019: US$26.8 million).

 

The Group's reserve based loan was sized on a borrowing base drawn from projected cash flows from the Montara assets, and based on proved and probable producing reserves but including certain infill wells.  This borrowing base was subject to scheduled semi-annual redeterminations and as such, and in the event of a significant reduction in the borrowing base, there was a risk that scheduled repayments might increase to offset any such borrowing base deficiency.  The existing borrowing base, as assessed by the lenders as at 31 December 2020, was significantly above aggregate commitments, and was fully repaid on 31 March 2021.  During the life of the loan, no semi-annual redetermination resulted in an increase in scheduled repayments, or the determination of any borrowing base deficiency.

 

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 and ARO accretion 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
2020
Non-interest bearing	-	36,740	38	352,771	(69,021)1	320,528
Fixed interest rate   instruments	6.049	13,448	14,042	-	(1,707)	25,783
Variable interest rate   instruments	7.570	7,445	-	-	(149)	7,296
		57,633	14,080	352,771	(70,877)	353,607
2019
Non-interest bearing	-	27,802	5,052	377,882	(102,460)1	308,276
Fixed interest rate   instruments	7.317	20,228	50,507	-	(8,463)	62,272
Variable interest rate   instruments	7.735	44,425	7,477	-	(2,779)	49,123
		92,455	63,036	377,882	(113,702)	419,671

 

¹ Relates to ARO accretion expense.

 

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
2020
Non-interest bearing	-	4,379	-	-	4,379
Variable interest rate   instruments	-*	89,441	-	-*	89,441
		93,820	-	-*	93,820
2019
Non-interest bearing	-	36,318	-	-	36,318
Variable interest rate   instruments	-*	89,419	10,000	-*	99,419
		125,737	10,000	*	135,737

 

*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.

 

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 2020.  The Group is not subject to externally imposed capital requirements.

 

		2020 USD'000		2019 USD'000
Gearing ratio
Debt		(7,296)		(49,123)
Cash and cash equivalents		81,996		75,934
Restricted cash		7,445		13,485
Cash less borrowings		82,145		40,296

 

Borrowings comprise long and short-term borrowings, incorporating effective interest method financing costs, and excludes derivatives, as detailed in Note 31.  Cash and cash equivalents include the Montara assets' minimum working capital cash balance of US$15.0 million required under the RBL, while restricted cash comprises the US$7.4 million in the RBL debt service reserve account (2019: US$13.5 million).  The restricted cash in 2020 excludes the US$1.0 million cash collateralised bank guarantee placed with the Indonesian regulator in respect of the JSA entered by the Group in Indonesia.  The restricted cash in 2019 excludes the US$10.0 million deposited in support of a bank guarantee to a key supplier in respect of the Stag FSO.  Equity includes all capital and reserves of the Group that are managed as capital.

 

The Group's overall strategy remains unchanged from 2019.

 

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

Financial assets/financial liabilities

Fair value (USD'000) as at

Fair

Valuation

Significant

unobservable

2020

2019

value hierarchy

technique(s) and key input(s)

unobservable input(s)

inputs to fair value

Assets

Liabilities

Assets

Liabilities

Derivative financial instruments

1) Oil price swaps and calls (Note 34)

-

471

5,275

-

Level 2

Third party   valuations   based on   market   comparable   information.

n.a.

n.a.

Others - contingent consideration from Montara business acquisition

2) Contingent consideration (Note 29)

-

-

-

359

Level 3

Based on the   nature and the   likelihood of   occurrence of   the trigger   event. Fair   value is   estimated   using future   Dated Brent oil   price forecasts   at the end of   the reporting   period, taking   into account     the time value   of money and   volatility of oil   prices.

Expected   future oil   price     volatility of    25% is   based on   an analysis   of Dated     Brent oil   price movements prior to the acquisition date.

A slight   increase in   Dated Brent   oil prices   would   result in a   significant increase in the fair value and vice versa.

Relationship

of

Financial assets/financial liabilities

Fair value (USD'000) as at

Fair

Valuation

Significant

unobservable

2020

2019

value hierarchy

technique(s) and key input(s)

unobservable input(s)

inputs to fair value

Assets

Liabilities

Assets

Liabilities

Others - contingent consideration from Lemang PSC acquisition

3) Contingent consideration (Note 15)

-

4,436

-

-

Level 3

Based on the   nature and   the likelihood   of the   occurrence of   the trigger   events.  Fair   value is   estimated,   taking into   consideration   the estimated   future gas   production   schedule,   forecasted   Dated Brent   oil prices and   Saudi CP   prices and   respective   price volatility   at the end of   the reporting   period, as well   as the effect   of time value   of money.

Gas production   schedule could   be changed   depending on   future gas   contract   negotiations.   Expected   future oil   price volatility   is based on   an analysis of   Dated Brent   oil price and   Saudi CP price   movements   as at Closing   Date.

A change in   gas   production   schedule or   significant   increase in   Dated Brent   oil prices   and Saudi CP   prices   would result   in a   significant   increase in   the fair   value.

 

 

36.  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 assets		Exploration/ development
	Australia USD'000		SEA USD'000		Corporate USD'000			Total USD'000
2020
Revenue
Liquids revenue	217,938		-		-			217,938
Production cost	(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		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
2019
Revenue
Liquids revenue	325,406		-		-			325,406
Production cost	(119,898)		-		-			(119,898)
DD&A	(90,277)		(113)		(356)			(90,746)
Staff costs	(9,595)		(3,543)		(8,889)			(22,027)
Other expenses	(4,699)		(278)		(4,402)			(9,379)
Other income	2,971		2		6			2,979
Finance costs	(16,387)		(7)		(49)			(16,443)
Other financial gains	3,389		-		-			3,389
Profit/(Loss) before tax	90,910		(3,939)		(13,690)			73,281
Additions to non-current   assets	84,444		20,456		65			104,965
Non-current assets	461,053		116,162		943			578,158

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 of US$19.7 million (2019: US$16.0 million) are excluded from the segmental note but included in the Group's consolidated statement of financial position.  

 

 

 

Revenues arising from producing assets in 2020 of approximately US$217.9million (2019: US$325.4 million) primarily arose from sales to the Group's largest customer.

 

 

37.  FINANCIAL CAPITAL COMMITMENTS

 

Certain PSC's and service concessions' have firm capital commitments.  The Group has the following outstanding minimum exploration commitments:

 

SEA portfolio PSC operational commitments

 

		2020 USD'000		2019 USD'000
Not later than one year		10,000		10,000
More than 5 years		7,284		-
		17,284		10,000

 

The SEA portfolio PSC operational commitments as at 31 December 2020 amounted to US$17.3 million (2019: US$ 10.0 million), and relates to the minimum work commitment outstanding for the Block 46/07 PSC and the Lemang PSC (2019: Block 46/07 PSC).

 

Under the terms of the Block 46/07 PSC, Jadestone is committed to drill one more appraisal well on the block.  The Company 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 on 19 March 2020 to delay the project, the Group is seeking Vietnam Government approval for a further extension in order to align drilling of the appraisal well with development of Nam Du/U Minh. The request of extension was submitted in December 2020.  The Group is committed to the project and expects to receive approval for the extension request in due course.

 

Under the terms of the Lemang PSC, Jadestone has inherited an operational commitment of US$7.3 million consisting of one exploration well and a 3D seismic acquisition program.  The commitment was carried over from the previous exploration period and is expected to be fulfilled during the future gas production period.

 

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 Montara:

 

		2020 USD'000		2019 USD'000
Not later than one year		8,977		19,441

 

 

 

 

38.  EVENTS AFTER THE END OF THE REPORTING PERIOD

 

Corporate reorganisation

 

The Company in undertaking an internal reorganisation to effect a re-domicile of the ultimate holding company to the United Kingdom.  A newly incorporated English company, Jadestone Energy plc has been established for this exercise.  Following the approval from shareholders and required court approvals, the shares of the Company will be replaced on a one-for-one basis with shares in Jadestone Energy plc.  The estimated effective date for the internal organisation is on 23 April 2021.  Jadestone Energy plc is anticipated to be admitted to AIM for trading on 26 April 2021.

 

The internal reorganisation will not result in a change in control in the ultimate holding company of the Jadestone group of companies and, accordingly, will not result in a change in control in the ultimate shareholding in any of the companies or assets of the Jadestone group of companies.  Further, the internal reorganisation will not result in a change in the management of any of the companies or assets of the Jadestone group of companies.

 

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 price protection.  The swap price, referenced to Dated Brent, was set at US$61.40/bbl.

 

 

39.  RELATED PARTY TRANSACTIONS

 

During the year, the Group did not enter into any transactions with related parties other than the following:

 

Compensation of key management personnel

 

		2020 USD'000		2019 USD'000
Short-term benefits		6,284		6,746
Other benefits		1,006		1,052
Share-based payments		816		1,038
		8,106		8,836

 

The total remuneration of key management members in 2020 (including salaries and benefits) was US$8.1 million (2019: US$8.8 million) and recognised as part of the Group's staff costs as disclosed in Note 7.

 

 

 

Compensation of directors

 

	Short-term benefits(a)		Other benefits(a)		Share-based payments		Total compensation
	USD'000		USD'000		USD'000		USD'000
2020
A. Paul Blakeley	991		324		186		1,501
Daniel Young	696		189		114		999
Dennis McShane	119		-		16		135
Iain McLaren	79		-		10		89
Robert Lambert	70		-		10		80
Cedric Fontenit	66		-		9		75
David Neuhauser	57		-		10		67
Lisa Stewart	74		-		11		85
	2,152		513		366		3,031
2019
A. Paul Blakeley	1,302		350		233		1,885
Daniel Young	707		174		139		1,020
Dennis McShane	130		-		21		151
Iain McLaren	81		-		13		94
Eric Schwitzer	68		-		25		93
Robert Lambert	69		-		13		82
Cedric Fontenit	66		-		9		75
David Neuhauser	56		-		12		68
Lisa Stewart	6		-		-		6
	2,485		524		465		3,474

 

^(a)   Short-term benefits comprise salary, director fee as applicable, performance pay, pension and other allowances.  Other benefits comprise benefits-in-kind.

 

 

40.  RECLASSIFICATION OF COMPARATIVE FIGURES

 

Certain comparative figures in the consolidated financial statements of the Group have been reclassified to conform to the presentation in the current period and to better reflect the nature of the respective items in the Group's consolidated financial statements. 

 

The reclassification made in the consolidated statement of profit or loss is related to third party contractor costs, which are now included within staff costs.  The reclassifications made in the consolidated statement of financial position are the Australia seismic costs, which are now included within intangible exploration assets.  Additionally, provisions have been reclassified from trade and other payables, and are now presented separately in the face of the consolidated statement of financial position.

 

In the consolidated statement of cash flows, the write-off of inventories has been reclassified from inventories movement to non-cash adjustment items, and the collection of PRRT receivables has been reclassified from trade and other receivables movement to tax refunded under operating activities.  

 

 

 

The reclassifications impact the following items:

 

		As previously reported USD'000		Reclassification USD'000		As reclassified USD'000
Consolidated statement of profit or loss and other   comprehensive income for the year ended   31 December 2019
Staff costs		(19,714)		(2,313)		(22,027)
Other expenses		(11,692)		2,313		(9,379)
Consolidated statement of financial position as at   31 December 2019
Intangible exploration assets		116,096		1,344		117,440
Oil and gas properties		383,018		(1,344)		381,674
Provisions - non-current		(280,418)		(415)		(280,833)
Other payables - non-current		(359)		359		-
Trade and other payables - current		(27,962)		2,163		(25,799)
Provisions - current		-		(2,107)		(2,107)
Consolidated statement of cash flows for the year   ended 31 December 2019
Inventories written off		-		164		164
Increase in trade and other receivables		(9,483)		(700)		(10,183)
Increase in inventories		(7,346)		(164)		(7,510)
Tax refunded		1,851		700		2,551