2020 Half Year Results and Dividend Declaration

RNS Number : 5944Y

Jadestone Energy Inc.

10 September 2020

 

  Jadestone Energy Inc.

2020 Half Year Results and Dividend Declaration

September 10, 2020-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 unaudited condensed consolidated interim financial statements (the "Financial Statements"), as at and for the six-month period ended June 30, 2020, and announces its maiden interim 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:

"I'm pleased to provide a first half 2020 report that underscores the resilience of our business.  Despite one of the most challenging periods our industry has ever faced, we have not compromised on our commitment to sustainability, and all our personnel remain safe with no recorded incidents of COVID-19, and no lapses in safety or environmental responsibility.  Against the backdrop of benchmark commodity prices 40% lower than the same period last year, our assets have remained essentially unimpaired.  In addition, through quick action in both managing our capital spending commitments and driving deeper efficiencies and cost savings throughout the entire business, we have kept our balance sheet strong.  These decisive steps through the first half of 2020, have ensured we maintain our financial strength and preserve our cash for what we expect to be a market recovery through next year.  We generated positive operating cash flows of US$57.1 million in H1 2020, we doubled our net cash position to a record high of US$78.3 million, and we are now in the final phase of repayment of our reserves based loan.  We expect to be entirely debt free at the end of Q1 2021.

"I see Jadestone's performance as a strong differentiator, and I am pleased to be able to translate this performance directly into shareholder returns through our maiden interim dividend of 0.54 US cents per share, declared today.  In addition, our H1 performance has facilitated ongoing execution of our growth strategy, including the Lemang acquisition in Indonesia, announced in June.  We are making excellent progress toward satisfying the closing conditions for Lemang and also for the New Zealand Maari acquisition, which remains on track for completion before the end of the year.

"Our focus on cost containment has extended to the deferment of several well workovers, and other non-critical interventions, as I see little point in chasing short term production volume into a profoundly weak crude oil market.  In addition, these activities could only have been achieved, if at all, by spending significant additional dollars to deliver the necessary equipment, spares and manpower, in a world constrained by COVID-19 related restrictions.  As a result, we are revising 2020 production guidance downwards to 11,000 - 12,500 bbls/d, to reflect our conscious decision to curtail all investment for the last eight months, and will only now restart these activities in response to recent price recovery.  We're nevertheless re-affirming the Group opex/bbl guidance, despite lower production, in part due to the over US$28.0 million of Project Clover initiatives implemented to date, and the capital expenditure guidance for this year as we target new investment recommencing in the new year.

"With an improved higher oil price, we are now executing a steady stream of workover and growth activities to re-build uptime performance and to grow production.  All equipment required for drilling the delayed infill wells from this year has been ordered, and the necessary drill rig availability has been secured for mid-2021.  Progress on both the Vietnam Nam Du/U Minh and Indonesia Lemang gas developments provide us optionality in pushing forwards with final investment decisions next year, with more detail on this to come as part of 2021 guidance.  These decisions will always be balanced by market conditions, as will our approach to inorganic activity, where we see a number of very material opportunities emerging across the region for 2021. The key will be to remain disciplined, remembering our strict evaluation criteria to ensure ongoing value add for shareholders, but having weathered the storm I'm now excited by what lies ahead."  

2020 FIRST HALF RESULTS SUMMARY

· H1 2020 production of 12,116 bbls/d, 8% lower than H1 2019 of 13,118 bbls/d, due to weather downtime and increased maintenance activities in Q1 2020, and an intentional pull-back on well workovers and well interventions;

· Net revenue for H1 2020 of US$115.7 million, down 3 3 % from H1 2019 of US$171.7 million due to lower oil prices, as a result of the fall in the demand for oil arising from COVID-19, and lower liftings;

· Average realised oil prices¹ in H1 2020 of US$46.47/bbl, 34% lower than H1 2019.  The average Dated Brent price incorporated into liftings in H1 2020 was US$38.36/bbl in H1 2020, or 43% down on H1 2019, while realised prices included an average premium over the benchmark of US$8.19/bbl (H1 2019: US$3.74/bbl); 

·     Costs of production  in H1 2020 of US$44.5 million, a decrease of 28% from H1 2019.  This equates to unit operating costs² of US$23.27/bbl, down 4% from H1 2019 of US$24.13/bbl, due to better cost efficiency achieved in the current period compared to H1 2019;

· Net profit after tax of US$5.4 million, down from US$30.9 million in H1 2019;

· H1 2020 positive operating cash flows of US$57.1 million, before movements in working capital, down 41% compared to H1 2019 of US$ 96.3 million;  

· Capital expenditure of US$19.5 million incurred during the period, down 37% compared to the prior period, due to the deferral of Nam Du/U Minh development in Vietnam this year and the 49H infill well last year;

· 2020 cashflow saving initiatives under Project Clover, the Group-wide efficiency and cashflow savings programme, of over US$24.0 million implemented to date, versus 2020 plan, plus a minimum of another US$4.0 million of savings to come from the change to the shuttle tanker crude offloading strategy at Stag.  Over US$10.0 million of the Clover savings was implemented and achieved in H1 2020, and there is a further US$10.0 million of additional Clover opportunities not yet implemented, but being pursued;  

· Net cash at June 30, 2020 of US$78.3 million, roughly double the amount at December 31, 2019 of US$39.3 million;

· 2020 production guidance revised to 11,000 - 12,500 bbls/d, as a result of a slowdown in well interventions, in part due to the greater costs and inefficiencies amidst the COVID-19 restrictions and a deliberate decision to push back generating additional production when oil prices were at their lowest ;

· 2020 full year opex/bbl and capex guidance re-affirmed at US$20.50 - 23.50/bbl and US$30 - 35 million, respectively;

· Ongoing execution of the Group's growth strategy with the acquisition of a 90% operated interest in the Lemang PSC, marking Jadestone's re-entry into Indonesia, one of the most prolific oil and gas jurisdictions in the Asia Pacific region, on track to close in Q1 2021;

· Strong progress towards closing the acquisition of a 69% operated interest in the Maari project, offshore New Zealand, with final government approvals expected Q4 2020; and

· A maiden interim dividend of 0.54 US cents/share has been declared, a total distribution of US$2.5 million, in line with guidance for the year of a full year dividend of US$7.5-12.5 million, split approximately one-third/two-thirds between interim/final.

¹   Realised oil price represents the actual selling price, net of marketing fees, and before any impact from hedging.  

² Unit operating costs per barrel excludes workover expenses, inventories written down and movement in inventories, but includes operational right-of-use assets lease payments.

Enquiries

Jadestone Energy Inc.	[phone] (Singapore)
Paul Blakeley, President and CEO	[phone] (Canada)
Dan Young, CFO	[phone] (UK)
Robin Martin, Investor Relations Manager	[e-mail]
Stifel Nicolaus Europe Limited (Nomad, Joint Broker)	[phone] (UK)
Ashton Clanfield / Callum Stewart / Simon Mensley
BMO Capital Markets Limited (Joint Broker)	[phone] (UK)
Thomas Rider / Jeremy Low / Thomas Hughes
Camarco (Public Relations Advisor)	[phone] (UK)
Georgia Edmonds / Billy Clegg / James Crothers	[e-mail]

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, Thursday, September 10, 2020, including a question and answer session.

The live webcast of the presentation will be available at the below webcast link.  Dial-in details are provided below.  Please register approximately 15 minutes prior to the start of the call. 

The results for the financial period ended June 30, 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=1360047&tp_key=4b87df21e2

Event conference title: Jadestone Energy Inc. - Half Year Results
Start time: 4:00 p.m. (Singapore), 9:00 a.m. (London)
Date: Thursday, September 10, 2020
Conference ID: 38552014

Dial-in number details:   https://www.jadestone-energy.com/notice-of-h1-2020-results-and-conference-call/

DIVIDEND

The directors have declared an interim dividend of 0.54 US cents/share on September 10, 2020 (or equivalent to 0.42 GB pence/share based on the current spot exchange rate of 0.7708) , equivalent to a total distribution of US$2.5 million before Canadian withholding tax.  The timetable for the payment of the 2020 interim dividend is as follows:

· Ex-dividend date: October 15, 2020

· Record date: October 16, 2020

· Payment date: October 30, 2020

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 some cash returns, after allowing for organic reinvestment needs, whilst maintaining a conservative capital structure, and not limiting options for inorganic growth.  The Company splits its dividend between an interim dividend and a final dividend in an approximate proportion of one third and two thirds respectively.  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")

Jadestone remains committed to ESG principles and continues to look to do things right the first time, for innovative ways to deliver exceptional value, all the while protecting the people and environments in which we operate.  The Group strives for excellence, with a target of zero incidents, accidents and impact wherever possible.

During H1 2020, the Group has continued 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, and the resultant required responses across the Group.  Jadestone has recorded no instances of COVID-19 among its workforce.

Our sustainability report included in the 2019 Annual Report, published in May 2020, provides further details and enhanced disclosures on the Group's ESG priorities.

The Board has agreed to adopt the Quoted Companies Alliance ("QCA") corporate governance code, as part of Jadestone's ongoing pivot from Canadian to UK corporate governance practises and norms.  The resultant changes that arise from the adoption of the QCA corporate governance code will be implemented by the end of 2020.

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 a floating production storage and offloading ("FPSO") vessel, the Montara Venture.  As at December 31, 2019, the Montara assets had proven plus probable reserves of 27.0mm barrels of oil, 100% net to Jadestone.

Production averaged 9,440 bbls/d (H1 2019: 10,908 bbls/d) for the first half of 2020.  This was lower than H1 2019 due to increased maintenance activities disruption due to cyclones and downtime .  In addition, H1 2019 benefitted from flush production following the voluntary shutdown in Q4 2018, to address the legacy inspection and maintenance backlog.

There were three liftings during H1 2020, resulting in total sales of 1,461,096 bbls, compared to 1,969,679 bbls in H1 2019, down as a result of lower production.

During H1 2020, Jadestone completed a 3D seismic acquisition covering the AC/L7 and AC/L8 licenses, to improve reservoir imaging for future infill wells and to assess prospects for future exploration targets on the licenses.  The data is currently being processed and is expected to be received in Q4 2020, with interpretation commencing immediately.

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 December 31, 2019, the field contained total proved plus probable reserves of 14.8mm barrels of oil, 100% net to Jadestone.

During the first half of 2020, production was 2,676 bbls/d, compared to 2,280 bbls/d in H1 2019. The prior period was negatively impacted due to rig preparation in advance of drilling the 49H infill well, and poor weather conditions.

H1 2020 saw two liftings for total sales of 518,193 bbls, compared to 368,523 bbls achieved from two liftings in H1 2019.

T he Group carried out three workovers in H1 2020, and three in H1 2019.  Following the decision by the lessor of the Dampier Spirit floating storage and offloading vessel to retire the vessel later in 2020 and to not provide a suitable replacement vessel under the terms of their agreement with Jadestone, the Company has developed a new operating strategy, utilising offtake tankers to directly offload Stag crude oil.  Jadestone has contracted a respected international tanker provider to supply modern double hulled tankers, operated to the requisite safety and environmental standards.  This new operating model has significant environmental risk mitigants over the existing model, by eliminating the need for ship to ship oil transfers in field.  The arrangement is also expected to realise annual savings of approximately 20% over the current FSO operation.  The first offtake tanker is scheduled to arrive in the field coincident with the Dampier Spirit departure in mid-September 2020.

New Zealand

Maari Oilfield

On November 16, 2019, the Group executed a sale and purchase agreement ("SPA") with 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 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 January 1, 2019 until the closing date, will be adjusted in the final consideration price.  As at December 31, 2019, the field holds 2P audited reserves of 12.2mm barrels of oil, net to Jadestone's 69% interest. 

Jadestone has made good progress towards closing the acquisition.  Most approvals are now in place and the Company expects final government approvals in Q4 2020 post the upcoming general election.

Pre-Production Assets

Vietnam

Block 51 PSC and Block 46/07 PSC

Jadestone holds a 100% operated working interest in the Block 46/07 PSC and the 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 Company opted to delay the project, as part of a review of its 2020 capital programme.

Discussions are continuing with the Vietnamese government on the FDP and a future gas sales agreement.

Block 05-1 PSC

On August 9, 2016, a wholly-owned subsidiary of the Company, signed a definitive agreement with Teikoku Oil (Con Son) Co. Ltd ("Teikoku"), a wholly-owned subsidiary of Inpex Corporation, as seller, for the acquisition of a 30% working interest in the Block 05-1 PSC, for a total cash consideration of US$14.3 million, and subject to normal closing adjustments.

On February 22, 2018, Teikoku delivered to Jadestone a purported notice of termination of the SPA, despite Teikoku having just received on February 9, 2018, the waiver by Vietnam Oil and Gas Group ("PVN"), of PVN's statutory pre-emption rights, held under Vietnamese law. 

Jadestone has not accepted Inpex's alleged termination and views the obligations of both parties under the SPA as continuing. 

The Group maintains its rights under the SPA and commenced arbitration proceedings against Teikoku on July 3, 2020, filing a notice of arbitration with the Singapore International Arbitration Centre, in accordance with the terms of the SPA.

Indonesia

Lemang PSC

On June 29, 2020, the Group executed an SPA with Mandala Energy Lemang Pte Ltd, to acquire an operated 90% interest in the Lemang PSC, onshore Indonesia, for a total initial headline cash consideration of US$12.0 million, to be funded from the Group's cash resources, and certain subsequent contingent payments.

The Lemang PSC is located onshore Sumatra, Indonesia.  The block includes the Akatara gas field, which was previously developed as an oil producing asset, and has a best estimate gross undeveloped wet gas in place of approximately 115 bscf which, at 90% interest, equates to unrisked 2C resources of 55.2 bscf sales gas, 2.2mm barrels of condensate, and 5.8mm boe of liquid petroleum gas¹. 

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 of Lemang re-establishes the Group's operating presence in Indonesia and adds further balance to the Group's portfolio by adding a new gas resource in a high growth emerging market context under PSC terms, and at a headline consideration of US$0.70/boe .

The Group anticipates completing the acquisition in Q1 2021.

Exploration Assets

Philippines

Service Contract 56 ("SC56")

Jadestone holds a 25% interest in SC56 in partnership with operator Total E&P Philippines B.V. ("Total").  Four wells have previously been drilled on SC56, resulting in the Dabakan and Palendag discoveries.  The current exploration period on the block ran until September 1, 2020. 

In September 2012, Total farmed into SC56 and assumed a 75% interest, and in August 2014 formally confirmed its intention to drill an exploration well on the Halcon prospect.  As a result of the Halcon confirmation, operatorship was transferred to Total, effective October 25, 2014.  The Group views Halcon as an economically viable prospect with significant resource potential. 

Total subsequently informed Jadestone that it did not intend to drill an exploration well on the Halcon prospect.  In December 2017, the Group commenced an arbitration action against Total, claiming failure by Total to drill the well and resultant damages.  On January 3, 2020, the arbitration tribunal ("Tribunal") found in favour of Jadestone and awarded monetary damages of US$11.1 million, plus legal fees of approximately US$4.3 million, less expenditure incurred prior to the breach.  

¹   Based on an independent review of contingent resources by ERCE, an independent qualified reserves auditor, and prepared for the Group in June 2020 in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook ("COGEH"), assuming 90% interest.  Based on 81% (assuming local government participation), total 2C Group resource is 15.5mm boe.  2C resource volumes presented represent the sub-class Development Pending, as defined by COGEH, and are presented on an unrisked basis.  The main contingencies are non-technical and include the finalisation of the gas sales agreement and project FID.  ERCE estimates the chance of development at 90%.

On March 26, 2020, the Group received notification of the final award from the Tribunal, which generated a net award to Jadestone of US$2.2 million after including all legal fees and the Group's share of the arbitration costs, and the deduction of litigation funding fees.

Under the terms of SC56, Total and Jadestone are committed to drill one more exploration well on the block prior to expiry.  On May 5, 2020, Total advised the Philippines Department of Energy that the COVID-19 pandemic represented a force majeure event under the service contract, and proposed a 12 month extension to the exploration phase of the license, to accommodate for the current circumstances.

The Group's net share of the penalty, in the event the well is not drilled, is currently estimated at approximately US$2.4 million.

Service Contract 57 ("SC57")

The Group holds a 21% working interest in SC57, but it has been under force majeure since 2011, and these conditions are expected to continue for the next 12 to 24 months.

FINANCIAL REVIEW

The following table provides select financial information of the Group, which was derived from, and should be read in conjunction with, the financial statements for the period ended June 30, 2020.

USD'000 except where indicated	Six months ended June 30, 2020	Six months ended June 30, 2019	Twelve months ended December 31, 2019
Sales volume, barrels (bbls)	1,979,289	2,338,203	4,496,164
Production, bbls/day	12,116	13,188	13,531
Realised oil price, $/bbl1	46.47	70.39	69.07
Revenue	115,669	171,707	325,406
Production costs	(44,466)	(62,057)	(119,898)
Operating costs/bbl ($/bbl)2	23.27	24.13	22.85
Adjusted EBITDAX2	36,606	97,925	187,505
Depletion, depreciation & amortisation costs/bbl ($/bbl)	16.14	16.72	16.94
Profit before tax	12,787	44,627	73,281
Profit after tax	5,360	30,944	40,505
Earnings per ordinary share: basic & diluted	0.01	0.07	0.09
Operating cash flows before movement in working capital	57,054	96,264	176,744
Capital expenditure	19,472	30,800	77,240
Outstanding debt2	25,574	74,940	50,144
Net cash/(debt)2	78,281	(8,561)	39,275

Production and liftings

The Group generated average production in H1 2020 of 12,116 bbls/d (H1 2019: 13,188 bbls/d).  Production at Montara was negatively impacted due to   increased maintenance activities and cyclone downtime in H1 2020.  In addition, H1 2019 benefitted from flush production following the voluntary shutdown in Q4 2018 to address the legacy inspection and maintenance backlog.  This was partially offset by increased production at Stag during H1 2020, compared to the same period in 2019, which was negatively impacted due to rig preparation in advance of drilling the 49H infill well and poor weather conditions.

¹   Realised oil price represents the actual selling price, net of marketing fees, and before any impact from hedging.

²   Operating cost per bbl, adjusted EBITDAX, outstanding debt and net cash/(debt) are non-IFRS measures and are explained on pages 10-12.

The Group had five liftings in the period resulting in sales of 1,979,289 bbls (H1 2019: 2,338,203 bbls), reflecting the lower production volumes compared to the same period in 2019.

Revenue and commodity prices

The Group generated US$115.7 million in revenues in H1 2020, compared to US$171.7 million in the same period in 2019, or a drop of 33%.  Revenues included hedging income of US$23.7 million (H1 2019: US$7.1 million).  

Average realised prices in H1 2020, before hedging and net of marketing fees, were US$46.47/bbl (H1 2019: US$70.39/bbl).  Dated Brent benchmark prices in H1 2020 averaged US$40.07/bbl, versus US$65.95/bbl in H1 2019, or a drop of 39%.  For Jadestone, the weighted average Dated Brent price embedded in its liftings in H1 2020 was US$38.36/bbl, a decrease of 43% from US$66.69/bbl recorded in H1 2019.  The weighted average premium over the benchmark in H1 2020 was US$8.19/bbl, compared to US$3.74/bbl in H1 2019.

Production costs

Production costs in H1 2020 were US$44.5 million (H1 2019: US$62.1 million), a decrease of US$17.6 million compared to H1 2019, due in part to a reduction in Montara logistics, including helicopter sharing arrangements with other operators due to COVID-19 restrictions, and higher expenditure in 2019 due to the non-routine replacement work associated with the riserless light well intervention.

Workover costs were almost half of 2019, as a result of the decision to defer several well interventions, due to the incremental cost and challenges of moving crew and equipment with logistics limitations imposed by COVID-19 restrictions, and to push back generating additional production when oil prices were at their lowest.

Unit operating costs per barrel were US$23.27 (H1 2019: US$24.13/bbl), before workovers, reflecting improved performance and better cost efficiency, compared to H1 2019, as well as the savings achieved through the Project Clover initiatives to date.

DD&A, other operating expenses and income

H1 2020 DD&A charges totalled US$39.3 million, versus H1 2019 of US$45.1 million, reflecting the lower lifted volumes.  The DD&A on a unit basis for oil and gas properties remained consistent with prior periods, but right-of-use assets depreciation increased due to entering into new lease contacts.

Other expenses in H1 2020 totalled US$7.9 million (H1 2019: US$4.8 million), with the increase predominately related to a portion of the seismic acquisition costs incurred at Montara, in particular those associated with areas outside the current license, and other non-routine expenditures.

H1 2020 other income is US$6.6 million (H1 2019: US$2.1 million), including the settlement of the SC56 license arbitration in favour of the Group, and increase in the fair value of the capped swap reflecting the decline in Dated Brent since December 31, 2019.

Taxation

The overall net tax expense of US$7.4 million (H1 2019: US$13.7 million) comprises current income tax expense of US$10.5 million (H1 2019: US$22.7 million), reduced by a deferred tax credit of US$3.1 million (H1 2019: US$9.0 million) arising from the unwinding of deferred tax liabilities.

Deferred tax liabilities in the Group's statement of financial position of US$63.2 million as at June 30, 2020 (December 31, 2019: US$64.8 million) primarily relate to the larger accounting basis for Montara's oil and gas properties, relative to its tax basis. This deferred tax liability unwinds in line with depletion charges recognised during the current period.

H1 2020 RECONCILIATION OF NET CASH

	US$'000	US$'000
Cash and cash equivalents, December 31, 2019		75,934
Restricted cash, December 31, 2019		13,485
Total cash and cash equivalent, December 31, 2019		89,419
Revenue	115,669
Other operating income	3,806
Operating costs	(43,771)
Staff costs	(10,790)
General and administrative expenses	(4,860)
Others	(3,000)
Cash flows from operations		57,054
Movement in working capital		9,249
Tax paid		(3,260)
Interest paid		(1,110)
Purchases of intangible exploration assets, oil and gas properties, and   plant and equipment		(12,985)
Other investing activities		251
Financing activities		(34,763)
Outstanding debt, June 30, 2020		(25,574)
Net cash1, June 30, 2020		78,281

Cashflows from operations

The Group generated positive cashflows from operations in H1 2020 of US$57.1 million, down from US$96.3 million in H1 2019, in part due to the 43% drop in benchmark oil prices in liftings versus H1 2019, and the lower volume of production and resultant liftings.

Financing activities

Financing activities of US$34.8 million (H1 2019: US$29.4 million) includes US$24.6 million of scheduled repayments on the Group's reserve based loan facility.

Capital expenditure

The Group's cash capital spend was US$13.0 million² (H1 2019: US$30.8 million), 58% lower than 2019 reflecting the delay to the Nam Du/U Minh development, in order to preserve the Group's balance sheet during the downturn, and the drilling of the 49H infill well in H1 2019.

¹   Net cash is a non-IFRS measure and is explained in page 12.

²   Total capital expenditure was US$19.5 million, comprising total capital expenditure paid of US$13.0 million, plus accrued capital expenditure of US$6.5 million.

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/(debt).

The following notes describe why the Group has selected these non-IFRS measures, and reconciles amounts to the nearest equivalent IFRS measure.

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, and workovers (to facilitate better comparability period to period). It also includes lease payments from right-of-use assets involved in production, and excludes depletion, depreciation and amortisation.  Adjusted aggregate production cost is then divided by total produced barrels for the prevailing period, to determine the unit cost per barrel.

		Six months ended		Six months ended		Twelve months ended
USD'000 except where indicated		June 30, 2020		June 30, 2019		December 31, 2019
Production costs (reported)		44,466		62,057		119,898
Adjustments
Lease payments related to operating activity1		10,005		7,113		15,947
Movement in oil inventories2		3,204		(38)		7,337
Write down of oil inventories3		(695)		-		-
Workover costs4		(5,675)		(11,542)		(30,331)
Adjusted production costs		51,305		57,590		112,851
Total production, barrels		2,205,042		2,386,968		4,938,867
Operating costs per barrel		23.27		24.13		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.  This adjustment is consistent with the accounting treatment prior to the implementation of IFRS 16 Leases on January 1, 2019, which transferred the expenses from production costs to DD&A and finance charges.  The lease payments are added back for consistency to prior years, and 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 volumes.

³ Write down of oil inventories is a non-cash adjustment based on the requirements of IAS 2 Inventories to reflect the closing inventories being recorded at the lower of cost or net realisable value, and as such it is not considered as a production cost.

⁴ 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.  By calculating an adjusted opex/bbl, production costs can then be better compared against prior periods.

Adjusted EBITDAX

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 adjusted for income tax, finance costs, other income and expense, DD&A, share based payments and other financial gains, but including operating lease costs associated with production, in part to be consistent with the calculation prior to the implementation of IFRS 16 Leases, but also to more closely reflect earnings generation.

The calculation of adjusted EBITDAX is as follow:

	Six months ended		Six months ended		Twelve months ended
USD'000	June 30, 2020		June 30, 2019		December 31, 2019
Revenue	115,669		171,707		325,406
Production cost	(44,466)		(62,057)		(119,898)
Staff cost	(11,425)		(10,322)		(22, 027 )
Other expenses	(7,862)		(4,786)		(9,379)
Other financial gains	359		2,278		3,389
Reported EBITDAX	52,275		96,820		177,491
Non-recurring
Hedge gain	(23,695)		(7,128)		(14,242)
Non-recurring opex1	4,413		8,359		23,785
Others2	3,972		2,152		3,860
Gain on contingent considerations	(359)		(2,278)		(3,389)
	(15,669)		1,105		10,014
Adjusted EBITDAX	36,606		97,925		187,505

¹ Includes one-off major maintenance/well intervention activities, in particular the riserless light well intervention in 2019 and a workover campaign at Skua 10 in 2020, as well as other non-recurring operating expenditures.

² Includes Montara seismic acquisition costs associated with areas outside the current license in 2020, as well as Montara transition team costs in 2019.

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 under 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. 

The Group currently has outstanding debt of US$25.6 million, which is fully repayable by the end of the first quarter of 2021.

USD'000		June 30, 2020		June 30, 2019		December 31, 2019
Long term borrowing		-		25,277		7,328
Short term borrowing		25,053		48,124		41,795
Add back: effective interest method financing costs		521		1,539		1,021
Outstanding debt		25,574		74,940		50,144

Net cash/(debt)

Net cash/(debt) 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		June 30, 2020		June 30, 2019		December 31, 2019
Outstanding debt		(25,574)		(74,940)		(50,144)
Cash and cash equivalents		95,457		51,880		75,934
Restricted cash		8,398		14,499		13,485
Net cash/(debt)		78,281		(8,561)		39,275

Net cash/(debt) is defined as the sum of cash and cash equivalents, which includes the minimum working capital balance of US$15.0 million required under the Group's reserve based loan ("RBL"), and restricted cash comprising US$8.4 million in the RBL debt service reserve account (June 30, 2019: US$14.5 million), less outstanding debt. Restricted cash, as shown here, excludes the US$10.0 million deposited in support of a bank guarantee to a supplier in respect of the Stag FSO.
 

2020 PRINCIPAL FINANCIAL RISKS AND UNCERTAINTIES

The Group's risk management framework provides a systematic process for the identification and management of the key risks and opportunities which may affect the delivery of the Group's strategic objectives.  Key performance indicators are set annually, and revised when necessary during the year.  They determine the level of risk the Group is willing to accept, in the pursuit of these objectives, and are a fundamental component of the Group's risk management framework.

The Board determines the key risks for the Group and monitors mitigation plans and performance on a regular basis.  Details of the principal risks and uncertainties facing the Group as at June 30, 2020, remain unchanged from the risks disclosed in the 2019 Annual Report.  The Group's risk mitigation activities also remain unchanged, with the exception of COVID-19, which is being continually monitored.

· Commodity price risk

· Foreign currency risk

· Interest rate risk

· Credit risk

· Liquidity risk

· Health, safety, environment and security

Impact of Coronavirus outbreak ("COVID-19")

On January 30, 2020, the World Health Organisation declared the COVID-19 outbreak a "Public Health Emergency of International Concern" and on March 10, 2020, declared it to be a pandemic.  Actions taken around the world to help mitigate the spread of COVID-19 include restrictions on travel, and a requirement to enter into quarantine in certain areas, and forced closures for certain types of public places and businesses.  COVID-19, and the actions taken to mitigate it, have had, and are expected to continue to have, an adverse impact on the economies and financial markets of many countries, including the geographical area in which the Group operates.

The substantially lower crude oil price has and will reduce the Group's revenue in 2020, but the Group has no plan to reduce its crude oil production as the Group has significant downside protection in place, including via its capped swap and a relatively competitive cash operating cost base.  The Group has hedged about a third of its planned production for the first nine months of 2020.  Additionally, the crude at both Stag and Montara have continued to generate a premium above benchmark crude oil prices.

In the absence of Vietnamese Government approvals for the Nam Du/U Minh field development plan in Q1 2020, and amidst the decline in oil prices, the Group announced on March 19, 2020 the deferral of the Nam Du/U Minh gas field development.  As a result of the continued fall in global oil prices, on April 22 , 2020, the Group announced the one year deferral of the Australian 2020 drilling campaign, to further preserve balance sheet strength and flexibility amidst the ongoing COVID-19 related uncertainty.

The Group has undertaken an impairment review of its non-financial assets, as at June 30, 2020, reflecting, among other factors, the then spot price for Dated Brent of US$41.83/bbl and the outlook for prices according to the world's three leading oil & gas consultancies.  Following this review, no impairment is required with respect to the Group's producing assets in Australia (Stag & Montara).  The Group has written down its closing Stag crude inventory as at June 30, 2020, by US$0.7 million, in-accordance with IAS 2 Inventories, to ensure the carrying value reflects the lower of cost or net realisable value.

 

GOING CONCERN

The directors have adopted the going concern basis in preparing these unaudited condensed consolidated interim financial statements, assessing the principal risks and having considered the impact of a severe but plausible downside scenario for COVID-19.  COVID-19 has contributed to a fall in the crude oil price since March 2020 as a result of the reduction in global oil demand.  The substantial lower crude oil price has, and will, reduce the Group's revenue in the current year.  

As part of the going concern analysis, a forward-looking going concern analysis was undertaken at some of the lower current third-party downside Dated Brent crude oil price outlooks, including US$42/bbl in H2 2020 and US$51/bbl in 2021.  Under the low-price scenario, the Group was able to generate positive operating cashflows without resorting to significant cuts in operating costs, and to continue as a going concern.

The directors believe that the Group is well placed to manage its financing and other business risks satisfactorily. The directors have a reasonable expectation that the Group will have adequate resources to continue in operation for at least 12 months from the date of these condensed consolidated interim financial statements. They therefore consider it appropriate to adopt the going concern basis of accounting in preparing the financial statements.

STATEMENT OF DIRECTORS' RESPONSIBILITIES

The directors confirm that to the best of their knowledge:

a. the condensed consolidated interim set of financial statements has been prepared in accordance with IAS 34 Interim Financial Reporting;

b. the interim management report includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and

c. the interim management report includes a true and fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein).

By order of the Board,

Paul Blakeley  Dan Young

President & Chief Executive Officer Chief Financial Officer

September 10, 2020  September 10, 2020

 

Disclaimer

Certain statements in this press release are forward-looking statements and information (collectively "forward-looking statements"), within the meaning of the applicable Canadian securities legislation, as well as other applicable international securities laws.  The forward-looking statements contained in this press release are forward-looking and not historical facts.

Some of the forward-looking statements may be identified by statements that express, or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of phrases such as "will likely result", "are expected to", "will continue", "is anticipated", "is targeting", "estimated", "intend", "plan", "guidance", "objective", "projection", "aim", "goals", "target", "schedules", and "outlook").  In particular, forward-looking statements in this press release include, but are not limited to, statements regarding the quantum and timing of expected savings under Project Clover, the impact of the COVID-19 pandemic, and related restrictions, and expected 2020 guidance with respect to (a) average production, (b) cash opex/bbl before workovers, (c) capital spending and (d) the 2020 full year maiden dividend.  Other forward-looking statements include commentary on the results of Montara 3D seismic acquisition and the Montara infill wells, the timing to conclude a gas sales and purchase agreement for the Nam Du/U Minh gas development, the outcome of the arbitration proceedings related to Block 05-1 PSC, the settlement arbitration related to SC56 and force majeure related to SC57, and the progress towards the completion and resultant closing of the Maari and Lemang PSC acquisitions. 

Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements.  By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur.  Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Jadestone.  Whilst the Group believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Group's control or within the Group's control where, for example, the Group decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward-looking statements. The forward-looking information contained in this news release speaks only as of the date hereof.  The Company does not assume any obligation to publicly update the information, except as may be required pursuant to applicable laws.

The technical information contained in this announcement has been prepared in accordance with the March 2007 guidelines endorsed by the Society of Petroleum Engineers, World Petroleum Congress, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers Petroleum Resource Management System.

Henning Hoeyland of Jadestone Energy Inc., a Subsurface Manager with a Masters degree in Petroleum Engineering who is a member of the Society of Petroleum Engineers and who has been involved in the energy industry for more than 18 years, has read and approved the technical disclosure in this regulatory announcement.

The information contained within this announcement is considered to be inside information prior to its release, as defined in Article 7 of the Market Abuse Regulation No. 596/2014, and is disclosed in accordance with the Company's obligations under Article 17 of those Regulations.

 

Glossary

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
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
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
reserves	hydrocarbon resource that is anticipated to be commercially recovered from known accumulations from a given date forward

 

Condensed Consolidated Statement of Profit or Loss and Other Comprehensive Income

for the six months ended June 30, 2020

		Six months ended June 30, 2020		Six months ended June 30,  2019		Twelve months ended December 31, 2019
		Unaudited		Unaudited		Audited
	Notes	USD'000		USD'000		USD'000
Consolidated statement of profit or loss
Revenue		115,669		171,707		325,406
Production costs	6	(44,466)		(62,057)		(119,898)
Depletion, depreciation and amortisation	6	(39,230)		(45,114)		(90,746)
Staff costs		(11,425)		(10,322)		(22,027)
Other expenses	6	(7,862)		(4,786)		(9,379)
Other income		6,576		2,098		2,979
Finance costs	7	(6,834)		(9,177)		(16,443)
Other financial gains		359		2,278		3,389
Profit before tax		12,787		44,627		73,281
Income tax expense	8	(7,427)		(13,683)		(32,776)
Profit for the period/year		5,360		30,944		40,505
Earnings per ordinary share
Basic and diluted (US$)	9	0.01		0.07		0.09
Consolidated statement of comprehensive    income
Profit for the period/year		5,360		30,944		40,505
Other comprehensive income/(loss)
Items that may be reclassified subsequently   to profit or loss:
Gain/(Loss) on unrealised cash flow   hedges		26,765		(29,691)		(30,542)
Hedging gain reclassified to profit or loss		(23,697)		(7,128)		(14,874)
		3,068		(36,819)		(45,416)
Tax (expense)/credit relating to   components of other comprehensive   income/(loss)		(921)		11,046		13,624
Other comprehensive income/(loss)		2,147		(25,773)		(31,792)
Total comprehensive income for the   period/year		7,507		5,171		8,713

Condensed Consolidated Statement of Financial Position

as at June 30, 2020

		June 30, 2020			June 30, 2019			December 31, 2019
		Unaudited			Unaudited			Audited
	Notes	USD'000			USD'000			USD'000
Assets
Non-current assets
Intangible exploration assets	10	135,105			101,238			117,440
Oil and gas properties	11	347,829			433,100			381,674
Plant and equipment	11	1,680			1,884			1,780
Right-of-use assets	11	51,070			69,303			59,787
Derivative financial instruments	16	-			2,738			-
Restricted cash		10,000			18,493			17,477
Deferred tax assets		16,535			21,198			16,012
Total non-current assets		562,219			647,954			594,170
Current assets
Inventories		46,399			18,248			31,411
Trade and other receivables		12,637			68,113			42,283
Derivative financial instruments	16	10,417			11,251			5,275
Restricted cash		8,398			6,006			6,008
Cash and cash equivalents		95,457			51,880			75,934
Total current assets		173,308			155,498			160,911
Total assets		735,527			803,452			755,081
Equity and liabilities
Equity
Capital and reserves
Share capital	12	466,573			466,573			466,573
Share based payments reserve		24,492			23,066			23,857
Hedging reserves		5,835			9,707			3,688
Accumulated losses		(263,291)			(278,212)			(268,651)
Total equity		233,609			221,134			225,467
Non-current liabilities
Provisions	13	283,194			305,829			280,833
Borrowings	14	-			25,277			7,328
Lease liabilities		33,881			50,929			42,533
Deferred tax liabilities		63,155			72,339			64,825
Total non-current liabilities		380,230			454,374			395,519
		June 30,			June 30,			December 31,
		2020			2019			2019
		Unaudited			Unaudited			Audited
	Notes	USD'000			USD'000			USD'000
Current liabilities
Borrowings	14	25,053			48,124			41,795
Lease liabilities		20,420			19,430			19,739
Trade and other payables	15	22,574			29,668			25,799
Provisions	13	1,705			1,224			2,107
Tax liabilities		51,936			29,498			44,655
Total current liabilities		121,688			127,944			134,095
Total liabilities		501,918			582,318			529,614
Total equity and liabilities		735,527			803,452			755,081

Condensed Consolidated Statement of Changes in Equity

as at June 30, 2020

			Share
			based
	Share		payments		Hedging		Accumulated
	capital		reserve		reserves		losses		Total
	USD'000		USD'000		USD'000		USD'000		USD'000
As at January 1, 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   (loss)/income for the   year	-		-		(31,792)		40,505		8,713
Share-based compensation,   representing transaction   with owners, recognised   directly in equity	-		1,482		-		-		1,482
Shares issued, net of   transaction costs	11		-		-		-		11
Total transactions with   owners, recognised   directly in equity	11		1,482		-		-		1,493
As at December 31, 2019   /January 1, 2020	466,573		23,857		3,688		(268,651)		225,467
Profit for the period	-		-		-		5,360		5,360
Other comprehensive   income for the period	-		-		2,147		-		2,147
Total comprehensive   income for the period	-		-		2,147		5,360		7,507
Share-based   compensation,   representing transaction    with owners, recognised   directly in equity	-		635		-		-		635
As at June 30, 2020	466,573		24,492		5,835		(263,291)		233,609
			Share
			based
	Share		payments		Hedging		Accumulated
	capital		reserve		reserves		losses		Total
	USD'000		USD'000		USD'000		USD'000		USD'000
As at January 1, 2019	466,562		22,375		35,480		(309,156)		215,261
Profit for the year	-		-		-		30,944		30,944
Other comprehensive loss   for the period	-		-		(25,773)		-		(25,773)
Total comprehensive   (loss)/income for the   period	-		-		(25,773)		30,944		5,171
Share-based   compensation,   representing transaction    with owners, recognised   directly in equity	-		691		-		-		691
Shares issued, net of   transaction costs	11		-		-		-		11
Total transactions with   owners, recognised   directly in equity	11		691		-		-		702
As at June 30, 2019	466,573		23,066		9,707		(278,212)		221,134

Condensed Consolidated Statement of Cash Flows

for the six months ended June 30, 2020

		Six months		Six months		Twelve
		ended		ended		months ended
		June 30,		June 30,		December 31
		2020		2019		2019
		Unaudited		Unaudited		Audited
	Notes	USD'000		USD'000		USD'000
Operating activities
Profit before tax		12,787		44,627		73,281
Adjustments for:
Depletion, depreciation and amortisation	6	30,352		38,732		75,870
Depreciation of right-of-use assets	6 / 11	8,878		6,382		14,876
Other finance costs	7	5,260		5,436		10,376
Interest expense	7	1,574		3,741		6,067
Write down of inventories		695		-		-
Share based payments		635		691		1,482
Loss on ineffective hedge recycled to   profit or loss		2		516		633
Fair value gain on foreign exchange   forward contracts		(2,076)		-		-
Change in Stag FSO provision		(443)		(1,445)		(1,717)
Decrease in fair value of Montara   contingent payments		(359)		(2,278)		(3,389)
Interest income		(251)		(578)		(1,260)
Write-off of oil and gas properties	11	-		533		533
Unrealised foreign exchange gain		-		(93)		(8)
Operating cash flows before movements   in working capital		57,054		96,264		176,744
Decrease/(Increase) in trade and other   receivables		29,646		(36,013)		(9,483)
Increase in inventories		(10,234)		(1,049)		(7,346)
Decrease in trade and other payables		(10,163)		(1,443)		(12,431)
Cash generated from operations		66,303		57,759		147,484
Interest paid		(1,110)		(2,776)		(4,698)
Tax (paid)/refunded		(3,260)		6,237		1,851
Net cash generated from operating   activities		61,933		61,220		144,637
		Six months		Six months		Twelve
		ended		ended		months ended
		June 30,		June 30,		December 31,
		2020		2019		2019
		Unaudited		Unaudited		Audited
	Notes	USD'000		USD'000		USD'000
Investing activities
Payment for oil and gas properties	11	(1,750)		(25,268)		(43,817)
Payment for plant and equipment	11	(106)		(374)		(502)
Proceeds from disposal of plant and   equipment		-		4		4
Payment for intangible exploration assets	10	(11,129)		(4,639)		(12,933)
Transfer from debt service reserve   account		5,087		4,145		5,159
Interest received		251		578		1,260
Net cash used in investing activities		(7,647)		(25,554)		(50,829)
Financing activities
Net proceeds from issuance of shares		-		11		11
Repayment of borrowings		(24,570)		(29,406)		(54,203)
Repayment of lease liabilities		(10,193)		(7,372)		(16,671)
Net cash used in financing activities		(34,763)		(36,767)		(70,863)
Net increase/(decrease) in cash and cash   equivalents		19,523		(1,101)		22,945
Effect of translation on foreign currency   cash and cash balances		-		-		8
Cash and cash equivalents at beginning   of the period/year		75,934		52,981		52,981
Cash and cash equivalents at end of the   period/year		95,457		51,880		75,934

Explanation Notes to the Condensed Consolidated Interim Financial Statements

for the six months ended June 30, 2020

1.  GENERAL INFORMATION

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

The Company's ordinary shares are listed on AIM, a market by the London Stock Exchange.  The Company trades under the symbol "JSE".  The Company was also listed on the TSX-V, but delisted on March 25, 2020 following a 12 month period of very small ordinary share trading volumes on the TSX-V and a very low level of Canadian resident shareholding.

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 and the Philippines.  The Group's current producing assets are in the Vulcan (Montara) and Carnarvon (Stag) basins, offshore Western Australia.

On November 18, 2019, the Group executed a sale and purchase agreement with 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 January 1, 2019 until the closing date will be adjusted in the final consideration price.  The Group anticipates completing the acquisition in Q4 2020.

The Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower, Singapore 079909.  The registered office of the Company is 10th Floor, 595 Howe Street, Vancouver, British Columbia V6C 2T5, Canada.

These financial statements were approved for issuance by the Company's Board of Directors on September 10, 2020, on the recommendation of the Audit Committee.

2.  DIVIDENDS

The directors have declared an interim dividend of 0.54 US cents/share, or equivalent to 0.42 GB pence/share based on the current spot exchange rate of 0.7708, equivalent to a total distribution of US$2.5 million (2019 interim dividend: nil).

3.  SIGNIFICANT EVENTS DURING THE PERIOD

Philippines SC56

On May 5, 2020, Total advised the Philippines Department of Energy that the COVID-19 pandemic represented a force majeure event under the service contract, and proposed a 12 month extension to the exploration phase of the license, to accommodate for the current circumstances.

The application for extension is in the process of review by the Philippines Department of Energy, and the outcome is expected in Q4 2020.

 

New Crude Offloading Strategy at Stag

On May 11, 2020, Altera Infrastructure Holdings LP, being the lessor of the Dampier Spirit floating storage and offloading vessel ("FSO") at Stag, announced its intention to retire the Dampier Spirit later in 2020 and, as required under the terms of their agreement with Jadestone, they have been unable to provide a suitable replacement vessel.

As a consequence, the Group has developed a new operating strategy, utilising offtake tankers to directly offload Stag crude oil, in place of the existing long term leased FSO.  To implement this strategy Jadestone has contracted a respected international tanker provider, who will supply modern double hulled tankers, operated to the requisite safety and environmental standards. 

This new operating model has significant environmental risk mitigants over the existing model, by eliminating the need for ship to ship oil transfers in field.  The arrangement is also expected to realise annual savings of approximately 20% over the current FSO operation.

The first offtake tanker is scheduled to arrive in the field coincident with the Dampier Spirit departure in mid-September 2020.  Ultimately multiple offtake tankers will rotate through the field on a schedule that optimises production continuity.

Acquisition of Operated 90% Interest in Lemang Production Sharing Contract ("PSC")

On June 29, 2020, the Group executed an acquisition agreement with Mandala Energy Lemang Pte Ltd to acquire an operated 90% interest in the Lemang PSC, for a total initial headline consideration of US$12.0 million.  The transaction is subject to regulatory approvals and once received, control of the Lemang project will transfer to the Group.  The Group anticipates completing the acquisition in Q1 2021.

4.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PREPARATION

These unaudited condensed consolidated interim financial statements (the "financial statements") are prepared in accordance with International Accounting Standard IAS 34 Interim Financial Reporting, as adopted by the European Union, on a going concern basis under the historical cost convention. 

These unaudited condensed consolidated interim financial statements do not comprise statutory accounts within the meaning of section 155 of the Canada Business Corporations Act.  They do not contain all disclosures required by International Financial Reporting Standards ("IFRS") for annual financial statements and should be read in conjunction with Jadestone's audited consolidated financial statements for the year ended December 31, 2019.  Jadestone's auditors reported on those accounts: their report was unqualified, did not draw attention to any matters by way of emphasis, and did not contain a statement under the Canada Business Corporations Act.

These financial statements have been prepared on an historical cost basis, except for financial instruments classified as financial instruments at fair value, which are stated at their fair values, and operating leases which are stated at the present value of future cash payments.

In addition, these financial statements have been prepared using the accrual basis of accounting.

GOING CONCERN

The directors are satisfied that the Group has sufficient resources to continue in operation for the foreseeable future, a period of not less than 12 months from the date of this report.  Accordingly, they continue to adopt the going concern basis in preparing the condensed consolidated interim financial statements.

RECLASSIFICATION OF COMPARATIVE FIGURES

Certain comparative figures in the financial statements of the Group have been reclassified to conform to the presentation in the current period, and in accordance with the audited consolidated financial statements for the year ended December 31, 2019.  These reclassifications were made to better reflect the nature of the respective items in the Group's financial statements. 

The reclassifications made in the statement of profit or loss are mainly related to third party contractor costs which are now included within staff costs.  The reclassifications made in the statement of financial position include provisions, reclassified from trade and other payables, which are now presented separately in the face of the statement of financial position, and an adjustment to the Montara purchase price accounting pursuant to IFRS 3 Business Combinations.

In the statement of cash flows, the change in provisions has been reclassified from trade and other payables movement to non-cash adjustment items.  Lease payments have been reclassified from an investing activity to a financing activity, and the movement in the debt service reserve account cash balance has been reclassified from cash and cash equivalents to be a standalone item in investing activities. 

Adoption of new and revised standards

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

The Group has applied the following standards and amendments that is relevant to the Group for the first time with effect from January 1, 2020.

-  Amendments to IFRS 3 Definition of a Business;

-  Amendments to IAS 1 and IAS 8 Definition of Material;

-  Amendments to IFRS 16 COVID-19 Related Rent Concessions; and

-  Amendments to References to the Conceptual Framework in IFRS Standards.

All amendments are effective for annual periods beginning on January 1, 2020 and generally require prospective application.

5.  CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

In the application of the Group's accounting policies, management is required to make judgments, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources.  The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant.  Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis.  Revisions to accounting estimates are recognised in the period in which the estimate is revised, if the revision affects only that period, or in the period of the revision and future periods, if the revision affects both current and future periods.

The key judgements and sources of estimation uncertainty remain the same since 2019 year end, the details of which have been disclosed in Jadestone's audited consolidated financial statements for the year ended December 31, 2019, other than the key assumptions below, which have been affected by COVID-19.

a)  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.  Estimates of future taxable income are based on forecast cash flows from operations.  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 low oil price resulting from COVID-19 could potentially impact the profitability of the Group, which may affect the ability of the Group to utilise the deferred tax assets recognised.  Based on the forecast cash flows prepared, management is of the opinion that the Group will have sufficient taxable profit in the future to utilise the deferred tax assets recognised.

b)  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 their anticipated recoveries.  Despite the current low oil price environment impacted by COVID-19, management believes that the current reserve estimates from 2019 year end remain reasonable, on the basis that the current low oil price level does not reflect the medium to long term outlook.  However, management will continue to closely monitor the development of the COVID-19 outbreak and related oil price outlook, and continue to evaluate its impact on the reserves estimates as at year end.

c)  Impairment of assets

The Group undertakes a regular review of asset carrying values to determine whether there is any indication of impairment.  For the impairment assessment in respect of the intangible exploration assets, the Group takes into consideration, among other indicators, 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, the Group develops a range of expected future cash flow outcomes based on third party audited reserves, future production profiles, commodity prices and costs.  Despite the current low oil price environment related to COVID-19, management believes that no impairment is required for its oil and gas properties, on the basis that the current low oil price level does not reflect the medium to long term outlook.  However, management will continue to closely monitor the development of the COVID-19 outbreak and related oil price outlook, and continue to assess the requirement of impairment for its non-financial assets as at year end.

d)  Asset restoration obligations

The Group estimates the future removal and restoration costs of oil production facilities, wells, pipelines and related assets at the time of the acquisition and/or the construction and 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 removal technologies.  Despite the current low oil price environment arising from COVID-19, management believes that no revision is required for reported asset restoration obligations, on the basis that the current low oil price does not reflect the medium to long term outlook.  However, management will continue to closely monitor the development of the COVID-19 outbreak and related oil price outlook, and continue to evaluate its impact on asset restoration obligations as at year end.

6.  OPERATING COSTS

		Six months ended		Six months ended		Twelve months ended
		June 30,		June 30,		December 31,
		2020		2019		2019
		Unaudited		Unaudited		Audited
		USD'000		USD'000		USD'000
Production costs		44,466		62,057		119,898
Depletion and amortisation of oil and   gas properties		30,146		38,537		75,443
Depreciation of plant equipment and   right-of-use assets		9,084		6,577		15,303
Total depletion, depreciation and   amoritisation		39,230		45,114		90,746
Corporate costs		6,726		3,414		8,040
Exploration expenses		972		-		-
Other operating expenses		164		1,372		1,339
Total other expenses		7,862		4,786		9,379

7.  FINANCE COSTS

		Six months ended		Six months ended		Twelve months ended
		June 30,		June 30,		December 31,
		2020		2019		2019
		Unaudited		Unaudited		Audited
		USD'000		USD'000		USD'000
Interest expense and others		3,671		5,816		10,491
Accretion expense		3,163		3,361		5,952
		6,834		9,177		16,443

During the current period, the Group paid interest of US$1.1 million (2019: US$2.7 million) related to the reserve based loan. 

8.  INCOME TAX EXPENSE

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

Income tax primarily relates to Australian corporate income tax at 30%, and Australian petroleum resource rent tax at 40%.

The overall net tax expense of US$7.4 million (H1 2019: US$13.7 million) comprises current income tax expense of US$10.5 million (H1 2019: US$22.7 million), reduced by a deferred tax credit of US$3.1 million (H1 2019: US$9.0 million) arising from the unwinding of deferred tax liabilities.  The deferred tax liabilities of US$63.2 million as at June 30, 2020 (December 31, 2019: US$64.8 million) primarily relates to the larger accounting basis for Montara oil and gas properties, relative to its tax basis.  The deferred tax liability unwinds in line with depletion charges recognised in the statement of profit or loss.

9.  PROFIT PER ORDINARY SHARE

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

		Six months ended		Six months ended		Twelve months ended
		June 30,		June 30,		December 31,
		2020		2019		2019
		Unaudited		Unaudited		Audited
		USD'000		USD'000		USD'000
Profit for the purposes of basic and   diluted per share, being the net profit   for the period attributable to equity   holders of the Company		5,360		30,944		40,505

		Six months ended		Six months ended		Twelve months ended
		June 30,		June 30,		December 31,
		2020		2019		2019
		Unaudited		Unaudited		Audited
		Number		Number		Number
Weighted average number of ordinary   shares for the purposes of basic EPS		461,042,811		461,038,759		461,040,802
Effect of dilutive potential ordinary   shares - share options		3,990,155		1,763,991		2,512,719
Weighted average number of ordinary    shares for the purposes of diluted EPS		465,032,966		462,802,750		463,553,521

The calculation of diluted EPS for the six months ended June 30, 2020 includes 3,990,155 of weighted average dilutive ordinary shares available for exercise from in-the-money vested options (six months ended June 30, 2019: 1,763,991).  Additionally, 607,821 of weighted average potential ordinary shares available for exercise, are excluded as they are out-of-the-money (six months ended June 30, 2019: 607,821). 

		Six months ended		Six months ended		Twelve months ended
		June 30,		June 30,		December 31,
		2020		2019		2019
Earnings per share (US$)		Unaudited		Unaudited		Audited
- Basic		0.01		0.07		0.09
- Diluted		0.01		0.07		0.09

10.  INTANGIBLE EXPLORATION ASSETS

	Total USD'000
Cost
As at January 1, 2019	95,607
Additions	5,631
As at June 30, 2019	101,238
Additions	16,202
As at December 31, 2019/January 1, 2020	117,440
Additions	17,665
As at June 30, 2020	135,105
Impairment
As at January 1, 2019/June 30, 2019/December 31, 2019/June 30, 2020	-
Net book value
As at June 30, 2019 (unaudited)	101,238
As at December 31, 2019 (audited)	117,440
As at June 30, 2020 (unaudited)	135,105

 

11.  PROPERTY, PLANT AND EQUIPMENT

		Oil and gas properties		Plant and equipment		Right-of-use assets		Total
		USD'000		USD'000		USD'000		USD'000
Cost
As at January 1, 2019		457,818		3,641		38,020		499,479
Changes in asset restoration   obligations		18,086		-		-		18,086
Additions		25,267		374		37,664		63,305
Disposal		-		(4)		-		(4)
Written off		(533)		-		-		(533)
As at June 30, 2019		500,638		4,011		75,684		580,333
Changes in asset restoration   obligations		(26,203)		-		-		(26,203)
Additions		18,550		128		1,149		19,827
Adjustments		-		-		(2,170)		(2,170)
As at December 31, 2019/   January 1, 2020		492,985		4,139		74,663		571,787
Additions		1,750		106		760		2,616
Termination		-		-		(307)		(307)
Adjustment		-		-		(394)		(394)
As at June 30, 2020		494,735		4,245		74,722		573,702
Accumulated depletion,   depreciation and amortisation
As at January 1, 2019		27,625		1,932		-		29,557
Charge for the period		39,913		195		6,382		46,490
Written off		-		-*		-		-*
As at June 30, 2019		67,538		2,127		6,382		76,047
Charge for the period		43,773		232		8,494		52,499
As at December 30, 2019/   January 1, 2020		111,311		2,359		14,876		128,546
Charge for the period		35,595		206		8,878		44,679
Termination		-		-		(102)		(102)
As at June 30, 2020		146,906		2,565		23,652		173,123
Net book value
As at June 30, 2019 (unaudited)		433,100		1,884		69,303		504,287
As at December 31, 2019   (audited)		381,674		1,780		59,787		443,241
As at June 30, 2020 (unaudited)		347,829		1,680		51,070		400,579

*Due to figures rounded to nearest thousand.

12.  SHARE CAPITAL

As at June 30, 2020, the Group had in issue 461.0 million allotted and fully paid ordinary shares with aggregate value of US$466.6 million.

In the six months ended June 30, 2019, the Group granted 6.5 million employee share options (H1 2019: 8.0 million) in respect of achievement of 2019 performance objectives.

13.  PROVISIONS

	June 30,  2020		June 30,  2019		December 31, 2020
	Unaudited		Unaudited		Audited
	USD'000		USD'000		USD'000
Non-current
Asset restoration obligations	278,543		299,069		275,422
Others	4,651		6,760		5,411
	283,194		305,829		280,833
Current
Others	1,705		1,224		2,107
	284,899		307,053		282,940

14.  BORROWINGS

		June 30, 2020 Unaudited USD'000		June 30, 2019 Unaudited USD'000		December 31, 2019 Audited USD'000
Non-current secured borrowings
Reserve based lending facility		-		25,277		7,328
Current secured borrowings
Reserve based lending facility		25,053		48,124		41,795
		25,053		73,401		49,123

 

15.  TRADE AND OTHER PAYABLES

		June 30, 2020 Unaudited USD'000		June 30, 2019 Unaudited USD'000		December 31, 2019 Audited USD'000
Trade payables		6,325		6,156		9,192
Other payables		84		13,049		6,166
Accruals		16,126		10,463		10,337
GST/VAT payables		39		-		104
		22,574		29,668		25,799

16.  DERIVATIVE FINANCIAL INSTRUMENTS

		June 30, 2020 Unaudited USD'000		June 30, 2019 Unaudited USD'000		December 31, 2019 Audited USD'000
Derivative financial assets
Designated as cash flow hedges
Commodity capped swap		8,341		13,989		5,275
Measured at fair value though profit or loss
Foreign exchange forward contracts		2,076		-		-
		10,417		13,989		5,275
Analysed as:
Current		10,417		11,251		5,275
Non-current		-		2,738		-
		10,417		13,989		5,275

The fair values of foreign exchange forward contracts were classified as Level 2 and calculated using market prices that the Group would pay or receive to settle the related contracts.

17.  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 development and exploration assets.  The geographic focus of the business is on Australia and Southeast Asia ("SEA").

 

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
Six months ended June 30, 2020 (unaudited)
Revenue
Liquids revenue	115,669			-				-					115,669
Production cost	(44,466)			-				-					(44,466)
DD&A	(39,036)			(56)				(138)					(39,230)
Staff costs	(5,965)			(907)				(4,553)					(11,425)
Other expenses	(5,055)			(115)				(2,692)					(7,862)
Other income	4,269			2,307				-					6,576
Finance costs	(6,823)			(1)				(10)					(6,834)
Other financial gains	359			-				-					359
Profit/(Loss) before tax	18,952			1,228				(7,393)					12,787
Additions to non-current   assets	7,576			12,288				417					20,281
Non-current assets	416,276			128,394				1,014					545,684
Six months ended June 30, 2019 (unaudited)
Revenue
Liquids revenue	171,707				-				-					171,707
Production cost	(62,057)				-				-					(62,057)
DD&A	(44,885)				-				(229)					(45,114)
Staff costs	(5,207)				(1,187)				(3,928)					(10,322)
Other expenses	(4,153)				(229)				(404)					(4,786)
Other income	2,134				-				(36)					2,098
Finance costs	(9,148)				-				(29)					(9,177)
Other financial gains	2,278				-				-					2,278
Profit/(Loss) before tax	50,669				(1,416)				(4,626)					44,627
Additions to non-current   assets	64,626				4,287				23					68,936
Non-current assets	525,628				100,017				1,111					626,756

	Producing assets		Exploration/ development
	Australia USD'000		SEA USD'000		Corporate USD'000			Total USD'000
Twelve months ended December 31, 2019 (audited)
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 comprise oil and gas properties, intangible exploration assets, right-of-use assets, restricted cash and plant and equipment used in corporate offices.

18.  EVENT AFTER THE REPORTING PERIOD

Vietnam PSC 05-1 arbitration

On August 9, 2016, Jadestone, as buyer, signed a definitive sale and purchase agreement ("SPA") with Teikoku, a wholly owned subsidiary of Inpex Corporation, as seller, for the acquisition of a 30% working interest in Block 05-1 PSC, for a total cash consideration of US$14.3 million, subject to normal closing adjustments.

On February 22, 2018, Teikoku delivered to Jadestone a purported notice of termination of the SPA, despite Teikoku having just received on February 9, 2018, the waiver by PVN, of PVN's statutory pre-emption rights, held under Vietnamese law.  The Group has not accepted Inpex's alleged termination and views the obligations of both parties under the SPA as continuing. 

Jadestone and Inpex engaged in negotiations over an extended period in 2018 and 2019, which the Group pursued with the objective of securing its interest in Block 05-1 PSC. 

On July 3, 2020, the Group announced it had filed a notice of arbitration with the Singapore International Arbitration Centre in accordance with the terms of the SPA against Teikoku, a wholly owned subsidiary of Inpex Corporation, in respect of Block 05-1 PSC offshore Vietnam.

 

END

 

 

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