Jadestone Energy 

2021 Full Year Results and Recommended Final Dividend Announcement

 

6 June 2022-Singapore: Jadestone Energy plc (AIM:JSE) ("Jadestone" or the "Company"), an independent oil and gas production company and its subsidiaries (the "Group"), focused on the Asia-Pacific region, reports today its audited consolidated financial statements (the "Financial Statements"), as at and for the financial year ended 31 December 2021, and announces a recommended final dividend of USȼ1.34 per share.  Management will host a conference call today at 9:00 a.m. UK time, details of which can be found in the release below.

 

Paul Blakeley, President and CEO commented:

 

"In a little over five years, we have transformed Jadestone from an exploration-led business into a leading independent Asia-Pacific upstream company with a significant production base, and material organic growth potential.  We delivered 10% production growth in 2021, exiting the year at much higher rates, and have guided to a further 36% increase in the current year.  This was on the back of a successful Montara activity programme and five months of initial contribution from the Peninsular Malaysia assets acquired during the year.

 

Our decision to remain unhedged has resulted in direct exposure to increasing oil prices and premiums, which are largely a consequence of structural under-investment in upstream capacity, although the distressing events in Ukraine this year are also having a clear impact.  Our year-end 2021 cash position of c.US$118 million has continued to grow in the first half of 2022, with pro-forma cash balances of US$180 million at end-May 2022, which includes the proceeds for barrels lifted in May but not yet received.  This cash position, and our forecast cash generation, places us in a strong position to execute our 2022 capital programme, take advantage of any high-quality additional M&A opportunities that we identify, and also to significantly increase shareholder returns. We are recommending a final dividend of US$6.25 million, a 25% increase on the second 2020 dividend, and we intend to return up to US$100 million of cash to shareholders over the next 12 months. This will be in the form of higher ordinary dividends, share buybacks and/or tender offers, starting with the recommended final 2021 dividend starting today. The actual level of shareholder returns will be influenced primarily by future oil pricing and premiums, as well as operational performance and business development activity, both organic and inorganic, over this period.

 

I'm very pleased to report that we have taken final investment decision on the Akatara gas field development onshore Indonesia, following necessary approvals by the Indonesian upstream regulator, with first gas on track for H1 2024.  We have also seen positive signs of progress on Nam Du / U Minh in Vietnam, with potential end users of gas production from the fields being directed by the government to enter into commercial discussions with Jadestone.  Progress towards completion of the Maari deal remains slow, however the New Zealand upstream regulator has confirmed that it has recommenced processing our application and we continue to respond promptly to any information requests, while working cooperatively with OMV, the seller.

 

Production in the first five months of 2022 has been impacted by the previously announced unplanned compressor outage at Montara and a temporary shut-in of the non-operated assets in Malaysia due to class recertification issues with the leased FPSO.  As a result, production in the first part of this year has averaged c. 15,700 boe/d, although in May we have seen production rates return closer to 17,000 boe/d.  We therefore still expect 2022 average production to be within the 15,500 - 18,500 boe/d guidance range, with the final outcome being influenced by ongoing activity to handle increased gas volumes at Montara (which longer-term may result in the installation of additional compression on the FPSO), the timing for production re-start from the non-operated Malaysia assets, and the outcome of the Stag infill drilling programme later this year.  It is worth noting that as we continue to look for ways to further improve Montara performance, installing additional compression will not only increase oil production, but also allow for more gas to be reinjected into the Montara field, thereby reducing the amount being flared.  Our unit operating expense and capital expenditure guidance are also unchanged at US$23.00-28.00/boe and US$90-105 million respectively.

 

 

We aim to marry further growth in our business with a focus on addressing our greenhouse gas profile.  In early June 2022 we announced a commitment to Net Zero Scope 1 and 2 greenhouse gas emissions from our operated assets by 2040.  Further detail on our asset decarbonisation pathways, with interim milestones, will be a key aspect of 2023 workstreams and we will release more news on this in due course.   We believe that our corporate strategy is well-suited to the energy transition, delivering essential energy from existing discovered and producing fields, and as a responsible operator with a demonstrable track record of delivering asset performance to the highest standards, providing confidence to sellers and host governments alike.  

 

Paul Blakeley

 

EXECUTIVE DIRECTOR,

PRESIDENT AND CHIEF EXECUTIVE OFFICER

 

 

2021 SUMMARY

 

USD'000 except where indicated	2021	2020
Production, boe/d	12,545	11,438
Realised oil price, US$/boe1	74.34	44.79
Revenue2	340,194	217,938
Operating costs per barrel of oil equivalent (US$/boe)3, 5	26.22	23.10
Adjusted EBITDAX3	157,948	62,582
Loss after tax	(13,742)	(60,178)4
Loss per ordinary share: basic & diluted (US$)	(0.03)	(0.13)
Dividend per ordinary share (USȼ)	1.93	1.62
Operating cash flows before movement in working capital	96,622	86,883
Capital expenditure	55,996	24,065
Outstanding debt3	-	7,386
Net cash3	117,865	82,055

 

Operational and financial summary

 

l  Full year production increased by 10% to 12,545 boe/d (2020: 11,438 bbls/d), in line with expectations and the guidance range.  The increase year-on-year was due to:

¡    The acquisition of the Peninsular Malaysia assets ("PenMal Assets") which contributed 2,539 boe/d (based on five month's production from closing on 1 August 2021 averaged over the full year);

¡    Stag production being broadly flat year-on-year at 2,359 bbls/d in 2021 (2020: 2,394 bbls/d); and

¡    Montara production declining to 7,647 bbls/d (2020: 9,045 bbls/d), as natural field decline, downtime during the 2021 activity programme and an unplanned shutdown to replace critical defective valves offset the initial contribution from the successful H6 infill well;

l  Revenue increased 56% to US$340.2 million (2020: US$217.9 million), a Group record, due to a 66% increase in realised prices and a 10% increase in lifted volumes; 

l  Jadestone's average realised price in 2021 was US$74.34/bbl (2020: US$44.79/bbl), a 66% increase year-on-year.  Average realised prices included an average premium over benchmark Dated Brent of US$3.39/bbl (2020: US$4.17/bbl);

Total lifted volumes for 2021 were aligned with production and increased 10% to 4.6 mmboe (2020: 4.2 mmbbls).  A total of 17 liftings (2020: 10) were achieved, including seven liftings for a total of 0.6 mmbbls and an additional 612 mcf of gas (equivalent to 0.1 mmboe) from the PenMal Assets;

 

l  Total production costs of US$206.5 million, significantly higher from US$105.3 million in 2020, in large part due to the contribution of the PenMal Assets of US$24.5 million, plus, the exceptional Skua well workovers programme of US$47.2 million, normal well workovers at Stag and Montara of US$19.8 million (2020: US$21.7 million) and increased repairs and maintenance ("R&M") following Project Clover of US$40.1 million (2020: US$22.5 million);

l  Adjusted annualised unit operating costs⁵ for 2021 were US$26.22/boe, within the guidance range, but up 14% from US$23.10/bbl in 2020, primarily due to higher routine R&M and lower production at Montara;

l  Adjusted EBITDAX improved 152% to US$157.9 million compared to US$62.6 million in 2020, predominately due to higher average realised prices in 2021 and the contributions from PenMal Assets since 1 August 2021;

l  Net loss after tax of US$13.7 million (2020: US$60.2 million loss after tax), reflecting the Skua workover costs at Montara and higher R&M expenses at both Stag and Montara.  During 2020, the net loss was due to lower realised prices and the US$50.5 million impairment of the SC56 licence offshore Philippines;

l  Despite the Skua workovers, operating cash flow generation in 2021 was strong at US$96.6 million, before movements in working capital, up 11% compared to 2020 of US$86.9 million;

l  Capital expenditure of US$56.0 million (2020: US$24.1 million) up 133% year-on-year, primarily due to the drilling of the H6 infill well at Montara;

l  Total 2021 major spending (capital expenditure and the Skua-10 & 11 workovers), of US$103.2 million, within the guidance range;

l  Cash balances of US$117.9 million at 2021-year end, 32% higher compared to 2020 at US$89.4 million, benefitting from favourable realised prices in the second half of the year.  Jadestone has been debt free following the final scheduled repayment of the Group's senior debt facility in Q1 2021;

l  Proven and probable reserves at year-end 2021 totalled 44.7 mmboe, a 20% increase on the end-2020 figure of 37.1 mmbbls, reflecting the addition of the PenMal Assets offset by production during the year; and

l  Recommended final dividend of USȼ1.34/share, equivalent to a distribution of US$6.3 million.  This results in total dividends of US$9.0 million in respect of 2021.

 

Business development

 

l  Completion of the acquisition of PenMal Assets from SapuraOMV on 1 August 2021, for a total cash consideration of US$20.0 million, comprising a headline price of US$9.0 million plus adjustments of US$11.0 million.  With an economic effective date of 1 January 2021, and taking into account cash received on completion, the Group received a cash amount of US$9.2 million at closing, net of the US$20.0 million due to SapuraOMV.  In January 2022, a further US$3.0 million was paid in recognition of a contingent payment triggered by Dated Brent averaging above US$65/bbl for 2021;

l  On 24 November 2021, the Group executed a settlement and transfer agreement with DP Hexindo Gemilang Jaya to acquire the remaining 10% interest in the Lemang PSC, for US$0.5 million and a waiver of unpaid amounts related to the PSC.  The transfer is subject to customary approvals and is expected to complete in the third quarter of 2022;

l  Jadestone's internal reorganisation completed on 23 April 2021, with Jadestone Energy plc becoming the parent company of the Group; and

l  Work continued to try to close the Maari acquisition in parallel with the New Zealand Government's legislative changes to the Crown Minerals Act.  Both the seller and Jadestone remain fully committed in trying to close the transaction as soon as possible.

2022 GUIDANCE

 

l  Announced a commitment to Net Zero Scope 1 and 2 greenhouse gas ("GHG") emissions from Jadestone's operated assets by 2040;

l  Production guidance of 15,500-18,500 boe/d maintained, which excludes any contribution from the pending Maari acquisition.  The outcome will be determined by work to address current gas handling constraints at Montara, the timing of return of the Malaysia non-operated assets which have been offline since earlier this year, and the impact of the Stag infill programme in the second half of the year;

l  2022 guidance for unit operating costs (US$23.00 - 28.00/boe) and capital expenditures (US$90.0 - 105.0 million) maintained;

l  Further inorganic growth opportunities in the Asia-Pacific region under active evaluation;

l  Intention to return up to US$100.0 million of cash to shareholders over the next 12 months, in the form of ordinary dividends (including the final recommended 2021 dividend announced today), share buybacks and/or tender offers.  The actual level of shareholder returns will be influenced primarily by future oil pricing and premiums, operational performance and business development activity over this period.

 

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

² Revenue in 2020 included hedging income of US$31.4 million, pursuant to the characterisation of the two-year capped swap programme as a cash flow hedge under IFRS 9 Financial Instruments.  Losses realised from the 2021 swaps of US$4.6 million were recognised in other expenses, pursuant to the characterisation of the ad hoc 2021 six-month swap programme as derivative instruments measured at fair value through profit or loss.  The 2021 swap programme covered a short time span (not exceeding a half yearly reporting period), whereas the capped swap programme crossed three annual reporting periods.

³ Operating costs per boe, adjusted EBITDAX, outstanding debt and net cash are non-IFRS measures and are explained in further detail below.

⁴ Loss after tax for 2020 included an impairment of US$50.5 million associated with capitalised intangible exploration costs at SC56, a deep-water exploration block associated with the previous management.

⁵ Unit operating costs per barrel of oil equivalent before workovers and movement in inventories but including net lease payments and certain other adjustments (see non-IFRS measures below).

 

Jadestone Energy plc.
Paul Blakeley, President and CEO	+65 6324 0359 (Singapore)
Phil Corbett, Investor Relations Manager	+44 7713 687 467 (UK)
	[email protected]
Stifel Nicolaus Europe Limited (Nomad, Joint Broker)	+44 (0) 20 7710 7600 (UK)
Callum Stewart / Jason Grossman / Ashton Clanfield
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 / Georgia Edmonds / James Crothers	[email protected]

 

The information contained within this announcement is considered to be inside information prior to its release, as defined in Article 7 of the Market Abuse Regulation No. 596/2014 which is part of UK law by virtue of the European Union (Withdrawal) Act 2018.

 

Conference call and webcast

The management team will host an investor and analyst conference call at 9:00 a.m. (London), 4:00 p.m. (Singapore) today, Monday, 6 June 2022, including a question and answer session.

 

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

 

The results for the period ended 31 December 2021 will be available on the Company's web site at: www.jadestone-energy.com/investor-relations/ .

 

Webcast link: https://produceredition.webcasts.com/starthere.jsp?ei=1549084&tp_key=81f0d2a39b

Event title: Jadestone Energy Full-Year 2021 Results

Time: 9:00 a.m. (UK time) / 4:00 p.m. (Singapore time)

Date: 6 June 2022

Conference ID: 23923977

 

Dial-in number details:

Country	Dial-In Numbers
United Kingdom	08006522435
Australia	1800076068
Canada (Toll free)	888-390-0546
France	0800916834
Germany	08007240293
Hong Kong	800962712
Indonesia	0078030208221
Japan	006633812569
Malaysia	1800817426
Netherlands	08000227908
New Zealand	0800453421
Singapore	8001013217
Spain	900834776
Sweden	0200899189
Switzerland	0800312635
United States (Toll free)	888-390-0546

 

 

DIVIDEND

 

On 6 June 2022, the Directors recommended a final 2021 dividend of 1.34 US cents/share, equivalent to 1.07 GB pence/share based on the spot exchange rate of 0.7954, an increase of 25% compared to 2020 and equivalent to a total distribution of US$9.0 million in respect of 2021.  The dividend will be paid on a gross basis, in US dollars.  The timetable for the dividend payment is as follows:

 

l  Ex-dividend date : 16 June 2022

l  Record date: 17 June 2022

l  Payment date: 5 July 2022

 

The Company's growth-oriented strategy remains unchanged; the business model is highly cash-generative, and, as a result, is fundamentally pre-disposed to providing cash returns, after allowing for organic reinvestment needs, whilst maintaining a conservative capital structure, and not unduly limiting options for further inorganic growth.  The Company intends to maintain and grow the dividend over time, in line with underlying cash flow generation.  The Company does not offer a dividend reinvestment plan and does not offer dividends in the form of ordinary shares.

The Group's robust financial position at the end of 2021 has strengthened further in 2022, with pro-forma cash balances of US$180.0 million at end-May 2022, which includes the proceeds for barrels lifted in May but not yet received, and no debt.  After careful consideration and while remaining focused on the Group's growth strategy, Jadestone's directors believe this cash position allows for a significant increase in shareholder returns.  As a result, Jadestone intends to return up to US$100.0 million of cash to shareholders over the next 12 months.  This will be in the form of higher ordinary dividends, share buybacks and/or tender offers, starting with the recommended final 2021 dividend announced today.  The actual structure of shareholder returns has not been finalised, while the final amount of shareholder returns will primarily depend on oil pricing and premiums going forward, as well as operational performance and business development activity, both organic and inorganic. 

 

ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG")

 

As a leading oil and gas development and production company in the Asia-Pacific region, Jadestone sees an opportunity to contribute to the energy security of the region whilst striving to deliver sustainable value for all of its stakeholders in a safe, as well as environmentally and socially responsible, manner.  The Company's primary focus is the acquisition of mid-life producing assets and, through additional capital investment, maximising reserves recovery, improving operating performance and reducing environmental impacts, including GHG emissions.  Mitigating GHG emissions from its upstream operations is a key pillar of Jadestone's strategy and of its approach to managing the climate risk exposure of the business.

 

The Group has committed to achieving Net Zero Scope 1 and 2 GHG emissions from its operated assets by no later than 2040.

 

A key element of the Net Zero commitment will be the development of an emissions reduction roadmap for major operated assets, which will inform the interim emission reduction targets for the Group, to be published by the end of 2023.  Where feasible, the Net Zero roadmap will prioritise actions aimed at reducing upstream emissions in the near-term.

 

Environment

 

Jadestone proactively manages environmental impacts associated with its operations through robust environmental management systems that focus on minimising pollution and protecting water resources whilst reducing carbon footprint from its upstream activities.

 

Despite continual challenges presented from the global pandemic in 2021, Jadestone's maintained operational performance across most areas of environmental impacts, with zero reportable environmental incidents and no environmental high potential incidents recorded during the reporting period at its operating facilities in Australia.  In 2021, Jadestone continued looking for ways to further improve its discharge quality streams.  The target of combined oil-in-water ("OIW") concentrations across Stag and Montara to be less than 14mg/litre was achieved and exceeded, with combined OIW at 10mg/litre based on daily averages.

 

Mitigating GHG emissions from upstream operations is a key pillar of Jadestone's strategy and of its approach to managing the climate risk exposure of the business.  Overall, 2021 Scope 1 GHG emissions from the Australian assets increased by 6%, when compared to 2020, against a target of 5% reduction.  This increase was driven by the performance of the Montara asset.  Volumes flared at Montara increased due to downtime in the gas reinjection system resulting from unplanned failure to auxiliary parts as well as production impacts resulting from drilling rig mobilisation.  The latter led to extended periods of time where Montara operations had to be either fully shut in or had partial production, without associated gas re-injection.  These events have been subject to thorough review to inform mitigation steps in the future.

 

In July 2021, Jadestone completed its acquisition of the PenMal Assets, adding two operated and two non-operated assets to its portfolio.  Jadestone worked with the previous operator, as well as the upstream arm of PETRONAS, to ensure that sound HSE and asset integrity practices were sustained throughout the transition period and were further built upon following the transfer of operatorship.  Going forward, Jadestone will continue to imprint its operational excellence ethos onto the new assets, work to reduce GHG emissions, manage water resources, maintain asset integrity and avoid major accidents.  Jadestone's 2022 sustainability reporting will reflect the operational performance of the PenMal Assets.

 

Social

 

Jadestone strives to create a safe and rewarding working environment for its workforce and goes beyond this to recognise the positive impacts the Company can make within the local communities.

 

Jadestone continued growing its asset base throughout 2021, which is reflected in permanent employee numbers for the year increasing by 60%.  The Company welcomed 108 new permanent and fixed-term employees as a result of the PenMal Assets acquisition in August 2021, with the majority of the offshore and supply base personnel engaged on the assets by the previous operator retained as Jadestone employees, while new hires were also added to the onshore team.  Jadestone has a clear focus on attracting and retaining local talent across its operations, resulting in 92% of Jadestone workforce representing its local country of operations.

 

Over the course of 2021, Jadestone's recorded three notable personal injury incidents across its operated assets offshore Australia.  These personal injury events are very significant for the Company, as protection of its employees is of paramount importance.  The injuries were managed in accordance with the Company's Injury & Illness Management procedure and were carefully investigated, with key learnings identified.  In the context of these incidents, the rolling monthly Total Recordable Incident Frequency Rate ("TRIFR") increased accordingly and was above target for the year.  Stress factors and longer shift patterns, created by uncertainty in a COVID-restricted world, were likely contributory factors and the company has largely addressed this returning to normal rosters.

 

In 2021, the Group enhanced community engagement programmes in all countries of operations, increasing its investment five-fold compared to the previous year, delivering tangible outcomes for the communities, which have been detailed further in Jadestone's 2021 Sustainability Report.

 

Governance

 

Jadestone's ability to create long-term value for its stakeholders is a key measurement of successful corporate governance, underpinned by high standards of business ethics and commitment to compliance.  Appropriate governance is also about ensuring that the most material ESG impacts and opportunities can be acted upon, and proactively managed throughout the organisation, with the tone set by the Board of Directors (the "Board").

Jadestone's Board updated its Board Charter and committee terms of reference throughout 2021 to reflect the increasing importance of Board-level oversight over climate and wider ESG-related risks and opportunities.  The Group had no incidents of violations of anti-bribery and anti-corruption laws in 2021 and has continued to maintain focus on timely regulatory approvals for new operations and growth projects, evidenced by securing gas sales agreement for the Akatara gas development in Indonesia, a key commercial milestone for the project.

 

Task Force on Climate-Related Financial Disclosures ("TCFD")

 

Throughout 2021, the Company has continued to implement the TCFD recommendations in its reporting and programmes, with a particular focus on climate risk integration and strategy considerations, commissioning a third-party to assist with conducting a climate scenario analysis across its portfolio, as well as to map out Net Zero strategic options.  The Company's first climate scenario analysis helped explore potential effects of climate change on the business, corporate strategy and financial performance, by modelling the possible changes to the price of hydrocarbons due to the energy transition, and the impact of tighter carbon-related regulations through additional carbon costs associated with the International Energy Agency's climate scenarios.  The results suggest that whilst some negative impact on the Company's operating cash flow would be observed, particularly in the longer-term, the Company portfolio and business strategy remains resilient.  The detail of the climate scenario analysis is set out in the Company's 2021 Sustainability Report.

 

Jadestone's 2021 Sustainability Report is published alongside the 2021 Annual Report.  It details the Group's approach to ESG and its performance across key focus areas for the 2021 calendar year, as well as commitments to further improvements in 2022.

 

 

OPERATIONAL REVIEW

 

Producing Assets

 

Australia

 

Montara project

 

The Montara project, in production licences AC/L7 and AC/L8, is located 254 km offshore Western Australia, in a water depth of approximately 77 metres.  The Montara project comprises three separate fields being Montara, Skua and Swift/Swallow, which are produced through an owned FPSO, the Montara Venture. 

 

As at 31 December 2021, the Montara assets had proven plus probable reserves of 20.9mm barrels of oil, 100% net to Jadestone. 

 

The fields produce light sweet crude (42^o API, 0.067% mass sulphur), which typically sells for average Dated Brent plus the average Tapis differential in the month of lifting.  The premium in 2021 ranged between US$0.43/bbl to US$2.94/bbl.  Premiums have increased in the first half of 2022, with the latest Tapis Brent differential at around US$6.47/bbl.

 

By late September 2021, the H6 infill development well had been successfully drilled and tied into the Montara field facilities and production commenced.  The well includes a circa 1,200 metre horizontal section of the reservoir in good quality oil-bearing sands.  The well delivered an initial rate, after clean-up, approaching 10,000 bbls/d.

 

Following the completion of the H6 well, two subsea workovers on Skua-10 and 11 were performed with Skua-10 returning to stabilised production of 1,500 bbls/d.  The return of production for Skua 11 was delayed to March 2022 due to required repairs on the subsea hydraulic connection, which were successfully achieved, and the well was brought back on-stream with stabilised production of 1,500 bbls/d.  

 

Montara production averaged 7,647 bbls/d in 2021 (2020: 9,045 bbls/d).  Lower production was the result of natural field decline and additional downtime associated with the drilling of H6 and the subsea workovers of Skua 10 and 11, plus an unscheduled shutdown in early 2021 to replace defective valves on the FPSO.

 

There were six liftings in 2021, resulting in total sales of 3.0 mmbbls, compared to 3.2 mmbbls in 2020 from the same number of liftings.

 

As part of Montara's three-to-four-year regular maintenance shutdown schedule, a three-week planned shutdown was originally planned for July 2022.  The key workstream during this planned shutdown was the replacement of the gas turbine core, which was moved forward to February/March due to the compressor outage earlier in the year.  As a result, the work scope of the planned shutdown has been significantly reduced, and all remaining critical maintenance activities can be carried out by a shorter one-week turn-around which has now been scheduled for later in 2022.  Rescheduling has the added advantage of avoiding competition for labour during the Australian offshore maintenance season, and a shorter shutdown allows for maximised oil production while oil price and premiums remain high.  A small amount of carry-over work may result from this but to be clear, none of this will impact on the integrity or safety of the Montara assets.

 

Stag oilfield

 

The Stag oilfield, in production licence WA-15-L, is located 60 km offshore Western Australia in a water depth of approximately 47 metres. 

 

As at 31 December 2021, the field contained total proved plus probable reserves of 12.6mm barrels of oil, 100% net to Jadestone. 

 

The Stag oilfield produces heavier sweet crude (18^o API, 0.14% mass sulphur), which historically sells at a premium to Dated Brent.  The premium in 2021 ranged between US$8.30/bbl to US$13.88/bbl.  The most recent lifting was agreed at a premium of US$23.72/bbl.

 

During 2021, the under-buoy hose, which is used for crude oil off-loading was replaced, an undertaking which is scheduled to occur only once every five years.  In addition, two extra well workovers were performed during the year compared to average, which partially reflects the clearing of a backlog of workovers which had built up in the early stages of the COVID-19 pandemic.

 

Production was maintained at 2,359 bbls/d in 2021, compared to 2,394 bbls/d in 2020, through ongoing production optimisation despite the constraints of the COVID-19 pandemic on workover execution.

 

There were four liftings in 2021, for total sales of 1.0 mmbbls, compared to 0.9 mmbbls in 2020 from the same number of liftings.

 

A once-in-every-three-years routine shut down was conducted in Q2 2022 to perform pressure vessel inspections.  In Q3 2022, the 50H and 51H infill development wells are scheduled to be drilled.  These development wells are anticipated to complete and come onstream in Q4 2022, and are expected to add around 1,000 bbls/d to current production levels.

 

Malaysia

 

Operated: PM 323 and PM 329 PSCs & Non-operated: PM 318 and AAKBNLP PSCs

 

On 1 August 2021, Jadestone completed the acquisition of the entire share capital of SapuraOMV Upstream (PM) Inc., for a cash consideration of US$20.0 million, comprising the headline price of US$9.0 million plus adjustments of US$11.0 million. 

 

The economic effective date of the acquisition was 1 January 2021, meaning the Group was entitled to the net cash generated since 1 January 2021 up to the completion date.  As a result, on 1 August 2021 the Group obtained gross cash held by SapuraOMV of US$29.2 million, resulting in a net cash receipt of US$9.2 million.

 

There are two separate potential contingent payments of US$3.0 million each related to the annual average Dated Brent price exceeding US$65/bbl in 2021 and US$70/bbl in 2022.  Dated Brent averaged US$70.91/bbl in 2021 and as a result the first US$3.0 million contingent payment was paid in January 2022.  Management believes the second contingent payment is probable and thus recognised a discounted provision of US$1.4 million in the annual financial statements for the year ended 31 December 2021.

 

Post completion the name of the acquired entity was subsequentially changed to Jadestone Energy (PM) Inc.

 

The PenMal Assets consist of four licences, two of which are operated by the Group.  The two operated licences comprise a 70% interest in the PM329 PSC, containing the East Piatu field, and a 60% interest in the PM323 PSC, which contains the East Belumut, West Belumut and Chermingat fields.  Both PSCs are located approximately 230km northeast of Terengganu in shallow water.  All fields are in production and have been developed by way of fixed wellhead and central processing platforms.  The two non-operated licences consist of 50% working interests in each of the PM318 PSC and in the Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields ("AAKBNLP") PSC.  The two non-operated PSCs are located in the same region as PM329 and PM323.

 

The PenMal Assets added immediate cash flow from 6,057 boe/d, on a net working interest basis, of which over 89% is oil.  The PenMal Assets produce light sweet crude that is blended to Tapis grade (43^o API, 0.04% mass sulphur). 

 

The PenMal Assets added 11.2 mmboe net working interest 2P reserves to the Group's 2P reserves as at 31 December 2021.

 

The Group believes there is scope to add incremental value to the PenMal Assets in the near-term through both reservoir optimisation, and production optimisation/enhancement activities across the PM323 and PM329 operated licences.  Gas reinjection is expected to be a key part of reservoir optimisation.  Production enhancement has been initially focused on restoring idle wells to production, while ongoing production optimisation is focused on both gas lift and topsides processes.  In addition, there are infill development well opportunities at the West Belumut and East Piatu fields, which will be evaluated in parallel with the East Belumut infill potential.

 

In 2021, average production from the PenMal Assets since the completion date was 5,377/bbls/d of oil and 4,084 mscf/d of gas (for  a total of 6,057 boe/d), net to Jadestone's working interest.  Averaged over the full year this is equivalent to 2,539 boe/d, net to Jadestone.  The average realised crude oil price was US$78.29/bbl, while gas sold for US$2.19/mcf.  The average premium in 2021 ranged between US$0.27/bbl to US$3.46/bbl.  The most recent lifting was agreed at a premium of US$4.33/bbl.

 

Between the date of acquisition and the year end there were seven liftings resulting in total sales of 582,181 boe and gas sales of 624.8 mcf.

 

On 7 February 2022, the Bunga Kertas FPSO, deployed at the non-operated assets, had its class suspended, resulting in the fields having to shut in and temporarily cease production.  The operator anticipates the FPSO will have its class reinstated by July/August 2022.  Since the class suspension there has been no production from the non-operated assets.

 

 

Pending acquisition

 

New Zealand

 

Maari project

 

On 16 November 2019, the Group executed a sale and purchase agreement with OMV New Zealand Limited ("OMV New Zealand"), to acquire an operated 69% interest in the Maari project, located 120 km offshore New Zealand, in a water depth of 100 metres, for a total headline cash consideration of US$50.0 million and subject to customary closing adjustments. 

 

The transaction has achieved several key milestones with regard to regulatory approvals, and the Group continues to focus on securing the remaining ministerial consents from the New Zealand Government, including the approval for transfer of operatorship. 

 

Jadestone and OMV New Zealand continue to work towards completion of the transaction.  The Group would assume the operatorship of the Maari project upon completion of the transaction.  The economic benefits from 1 January 2019 until the closing date will be adjusted in the final consideration price.  This is anticipated to be a net receipt to the Group. 

 

 

Pre-production Assets

 

Indonesia

 

Lemang PSC

 

The Lemang PSC is located onshore Sumatra, Indonesia.  The PSC contains the Akatara field, which has been substantially de-risked with 11 wells drilled into the structure, plus three years of oil production history, up until the field ceased oil production in December 2019. 

 

On 30 June 2021, the Minister of Mines and Energy of Indonesia issued a Ministerial decree that facilitates the development and commercialisation of the Akatara gas field, allocating gas sales from the gas field in the Lemang PSC to a subsidiary of PT Perusahaan Listrik Negara, the national electricity utility, and the associated production and sales of LPG to the local domestic market in Jambi province, together with condensate sales to a local buyer.  On 1 December 2021, a gas sale agreement was signed between Jadestone and PT Pelayanan Listrik Nasional Batam, as buyer. 

 

In early 2022, Jadestone launched a tender for the engineering, procurement, construction and installation contractor ("EPCI") for the Akatara development.  After a rigorous process, a recommendation on the EPCI contractor was made to the Indonesian upstream regulator, SKKMigas, in May 2022.  Regulatory approval was received in late May 2022 and the EPCI contract signed in early June 2022, allowing Jadestone to take a final investment decision ("FID") and accelerate development activity on the Akatara field.

 

The Akatara gas field has been independently estimated to contain a 2C gross resource (pre local government back-in rights) of 63.7 bcf of sales gas, 2.5 mmbbls of condensate and 5.6 mmboe of LPG, equating to a combined 18.7 mmboe of resource, or 16.8 mmboe net to Jadestone's existing 90% working interest.  Following FID, Jadestone will book it's share of economic Akatara gas resources at the end of 2022.

 

Jadestone is pursuing a low-cost development of the field, including efficient re-use of existing wells and infrastructure, thereby minimising incremental impact on the local environment.  The Akatara gas project remains on track for first gas in H1 2024.

 

 

On 24 November 2021, the Group announced the acquisition, subject to customary approvals, of the remaining 10% interest in the PSC from PT Hexindo Gemilang Jaya ("Hexindo").  Through this transaction, the Group's interest in the Lemang PSC will increase to 100%, pre local government back-in rights.  In return for the transfer of Hexindo's 10% stake, the Group will waive unpaid amounts related to Hexindo's interest in the Lemang PSC and will pay a consideration of US$0.5 million (inclusive of transfer taxes) subject to the approval of government, shareholders of Hexindo and the shareholders of Eneco Energy Limited, Hexindo's parent company.  Jadestone anticipates receiving the remaining approvals in Q3 2022.

 

Vietnam

 

Block 51 and Block 46/07 PSCs

 

Jadestone holds a 100% operated working interest in the Block 46/07 and Block 51 PSCs, both in shallow waters in the Malay Basin, offshore southwest Vietnam. 

 

The two contiguous blocks hold three discoveries: the Nam Du gas field in Block 46/07 and the U Minh and Tho Chu gas/condensate fields in Block 51, with 2C resources of 93.9 mmboe.

 

The Tho Chu discovery in Block 51 is currently under suspended development area status, with the exploration period expiring in June 2023.

 

The formal field development plan ("FDP") in respect of the Nam Du/U Minh development was submitted to the Vietnam regulatory authorities in late 2019.  The Group deferred the project in mid-March 2020, amid delays in Vietnamese Government approvals and the drop in global oil prices due to COVID-19.

 

Discussions are continuing with the Vietnamese Government and Petrovietnam to reinstate the project, agree a gas production profile for the development, as a precursor to a gas sales contract, and ultimately attaining government sanction for the field development.

 

Exploration Assets

 

Philippines

 

Service Contract 56 ("SC56")

 

In 2020, Total E&P Philippines B.V. ("Total") and Jadestone informed the Philippines Department of Energy of their intention to voluntarily surrender the entire interest in SC56 (Jadestone 25% working interest) and accordingly, to terminate the contract.  The effective date of termination was 21 December 2020. 

 

Following the termination, in Q3 2021, the Group paid US$1.5 million to the Philippines Department of Energy, related to the unfulfilled minimum work programme, net to Jadestone's 25% participating interest. 

 

Service Contract 57 ("SC57")

 

In 2006, the Group executed an agreement with the Philippines National Oil Company ("PNOC") to acquire a 21% working interest in SC57.  The acquisition required the approval of the Office of the President of the Philippines and in December 2021 the Philippines Department of Energy advised that such approval will not be granted.  The Group is now seeking reimbursement from PNOC for costs of approximately US$0.9 million which it incurred in relation to a 2008 seismic acquisition campaign.

 

 

 

Reserves and resources

 

Total Proved plus Probable Reserves (net, mmboe)
	Australia1	Malaysia2,3,4	Indonesia	Vietnam	Total Group
Opening balance, 31 December 2020	37.1	-	-	-	37.1
Acquisitions	0.0	12.5	-	-	12.5
Technical revisions	0.1	0.9	-	-	1.0
Production	(3.7)	(2.2)	-	-	(5.9)
Ending balance, 31 December 2021	33.5	11.2	-	-	44.7

 

As of 31 December 2021, the Group had proved plus probable oil reserves ("2P reserves") of 44.7 mmboe, a 20% increase on the end-2020 figure of 37.1 mmbbls.  The primary driver of the increase was the addition of 11.2 mmboe at year-end 2021 in respect of the PenMal Assets acquisition during the year.  The combined year-on-year reduction in the reserves at Stag and Montara fields reflected production during the year.  ERCE Equipoise Limited independently evaluated the Group's year-end 2021 reserves.

 

Total 2C Contingent Resources (net, mmboe)
	Australia	Malaysia	Indonesia5	Vietnam6	Total Group
Opening balance, 31 December 2020	-	-	16.8	93.9	110.7
Acquisitions	-	-	-	-	-
Technical revisions	-	-	-	-	-
Production	-	-	-	-	-
Ending balance, 31 December 2021	-	-	16.8	93.9	110.7

 

The Group's best case contingent resources ("2C resources") were unchanged year-on-year at 110.7 mmboe.  Of this figure, the Akatara gas field development comprises 16.8 mmboe.  The Group anticipates that the Akatara gas field 2C resources will be converted to 2P reserves following development sanction of the project.

 

 

Henning Hoeyland of Jadestone Energy plc., Jadestone's Australia Country Manager, with a Masters degree in Petroleum Engineering who is a member of the Society of Petroleum Engineers and who has been involved in the energy industry for more than 20 years, has read and approved the technical disclosure in this release.

 

 

 

 

¹ Proven and Probable Reserves for Jadestone's Australian assets have been prepared in accordance with the Canadian Oil and Gas Evaluation ("COGE") Handbook as the standard for classification and reporting.  Jadestone does not believe that there are significant differences between the COGE standard and the 2018 guidelines endorsed by SPE, WPC, AAPG and SPEE Petroleum Resource Management System.

² Proven and Probable Reserves for Jadestone's Malaysia assets have been prepared in accordance with the 2018 guidelines endorsed by SPE, WPC, AAPG and SPEE Petroleum Resource Management System.

³ Assumes oil equivalent conversion factor of 6,000 scf/boe.

⁴ The acquired 2P Reserves in Malaysia are based on an effective date of 1 January 2021.  As such, the production figure of 2.2 mmboe in the table above reflects production over the calendar year 2021. Jadestone's reported production for 2021 of 12,545 boe/d includes production from the PenMal assets from the completion of the assets (2 August 2021). The positive revision of 0.9 mmboe reflects an extension of. economic life on the back of higher oil prices.

⁵ Lemang PSC 2C resources based on ERCE Competent Person's Report effective 31 December 2020.

⁶ Vietnam 2C resources based on ERCE Competent Person's Report effective 31 December 2017.

 

FINANCIAL REVIEW

 

The following table provides select financial information of the Group, which was derived from, and should be read in conjunction with, the audited consolidated financial statements for the year ended 31 December 2021.

 

USD'000 except where indicated	2021	2020
Sales volume, barrels of oil equivalent (boe)	4,562,279	4,165,612
Production, boe/d	12,545	11,438
Realised oil price, US$/boe1	74.34	44.79
Revenue2	340,194	217,938
Production costs	(206,523)	(105,338)
Operating costs per barrel of oil equivalent (US$/boe)3	26.22	23.10
Adjusted EBITDAX3	157,948	62,582
Unit depletion, depreciation & amortisation (US$/boe)	13.67	16.24
Impairment	-	50,455
Profit/(Loss) before tax	1,080	(57,238)
Loss after tax	(13,742)	(60,178)
Loss per ordinary share: basic & diluted (US$)	(0.03)	(0.13)
Dividend per ordinary share (USȼ)	1.93	1.62
Operating cash flows before movement in working capital	96,622	86,883
Capital expenditure	55,996	24,065
Outstanding debt3	-	7,386
Net cash3	117,865	82,055

 

Benchmark commodity price and realised price

 

The average benchmark price incorporated into the Group's liftings was US$70.94/bbl in 2021, an increase of 75% compared to 2020 at US$40.61/bbl. 

 

The actual average realised price in 2021 increased broadly in line with the benchmark price, by 66% to US$74.34/bbl, compared to US$44.79/bbl in 2020.  The average premium for the year was US$3.39/bbl, compared to 2020 of US$4.17/bbl.  The decline in premiums was predominately due to the inclusion of PenMal Assets barrels with an average premium of $1.14bbl.  Stag averaged US$11.20/bbl (2020:11.45/bbl) and Montara US$1.14/bbl (2020: US$2.04/bbl).

 

Since the December 2021 year end, premiums have continued to increase with the most recent liftings achieving a premium of US$6.47/bbl, US$23.72/bbl and US$4.33/bbl, at Montara, Stag and PenMal Assets respectively. 

 

 

 

 

 

 

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

²  Revenue in 2020 included hedging income of US$31.4 million, pursuant to the characterisation of the two-year capped swap programme as a cash flow hedge under IFRS 9.  Losses realised from the 2021 swaps of US$4.6 million were recognised in other expenses, pursuant to the characterisation of the ad hoc 2021 six-month swap programme as derivative instruments measured at fair value through profit or loss.  The 2021 swap programme covered a short time span (not exceeding a half yearly reporting period), whereas the capped swap programme crossed three annual reporting periods.

³ Operating cost per boe, adjusted EBITDAX, outstanding debt and net cash are non-IFRS measures and are explained in further detail below.

 

Production and liftings

 

The Group generated average production of 12,545 boe/d in 2021, compared to 11,438 bbls/d in 2020.  Production increased due to the acquisition of PenMal Assets which generated average production of 6,057 boe/d since the date of acquisition, or 2,539 boe/d averaged over the full year.  Montara production declined in 2021 to 7,647 bbls/d from 9,045 bbls/d in 2020 due to natural field decline and downtime associated with the drilling of H6 and workovers on Skua 10 & 11, plus an unscheduled shutdown to replace defective valves on the FPSO.  Stag production in 2021 was 2,359 bbls/d, broadly in line with the 2,394 bbls/d achieved in 2020. 

 

The Group had 17 liftings during the year (2020: 10), resulting in sales of 4.6 mmbbls (2020: 4.2 mmbbls), reflecting the higher production compared to 2020.  The PenMal Assets contributed seven oil liftings since August, representing 0.6 mmbbls.  In addition, PenMal Assets produced and sold 624.8 mcf (approximately 0.1 mmboe) of natural gas, which is sold via pipeline directly to PETRONAS.

 

Revenue

 

The Group generated revenue of US$340.2 million in 2021, an increase of 56% compared to 2020 of US$217.9 million, and the highest revenue ever recorded by the Group.  The increase of US$122.3 million was predominately due to:

 

·      Higher average realised prices in 2021, compared to 2020 for Stag and Montara, contributing an additional US$115.3 million;

·      PenMal Assets generating oil revenues of US$45.6 million and gas sales of US$1.0 million (2020: nil);

·      A decrease of 0.2 mmbbls in lifted volumes at Montara and Stag in 2021 compared to 2020, resulting in a decline in revenues of US$8.3 million; and

·      Hedging income was nil¹ in 2021, a decline of US$31.4 million compared to 2020.  The Group's 24 month capped swap cash flow hedge programme ended on 30 September 2020.

 

Production costs

 

Production costs increased by 96% in 2021 to US$206.5 million, from US$105.3 million in 2020, predominately due to:

 

·      Workover costs of US$67.0 million (2020: US$21.7 million), mostly related to the subsea workovers at Skua 10 & 11 of US$47.2 million.  The Montara subsea workovers were a one-off event and differ from the pump replacements at Stag as they require a dedicated drilling rig, whereas the Stag workovers are undertaken by the hydraulic workover unit in place on the Stag platform.  There were nine workovers at Stag in 2021, compared to eight in 2020;

·      Repairs and maintenance costs of $45.2 million, compared to US$22.5 million in 2020, with the PenMal Assets contributing US$5.1 million and Australia an additional of US$17.6 million compared to 2020.  Montara incurred an additional US$11.6 million due to a once-in-every-three-year subsea flowline inspection, a subsea control module ("SCM") change-out on the Swift North well and higher fabric maintenance costs.  Stag incurred an additional US$6.0 million due to a once-in-every-five-years under-buoy hose replacement and also higher fabric maintenance costs;

·      Operating costs increased to US$61.6 million (2020: US$45.2 million), with the PenMal Assets contributing US$11.2 million, plus higher contractor charges at Stag and Montara from changing rosters in response to COVID-19 restrictions;

 

¹ The hedging loss in 2021 of US$4.6 million was recognised within other expenses, as opposed to offsetting against revenue, due to the adoption of a different accounting treatment for the 2021 commodity swap contracts.  The two-year capped swap programme was characterised as a cash flow hedge under IFRS 9 and realised gains were recognised as part of revenue.  Losses realised from the 2021 swaps were recognised in other expenses, pursuant to the characterisation of the ad hoc 2021 six-month swap programme as derivative instruments measured at fair value through profit or loss.  The 2021 programme covered a short time span (not exceeding a half yearly reporting period), whereas the capped swap programme crossed three annual reporting periods.

 

·      Logistics costs increased to US$20.2 million (2020: US$18.9 million), with the PenMal Assets contributing US$2.3 million;

·      Transportation costs of US$2.8 million in 2021 (2020: nil), reflecting the change in offtake arrangements at Stag following the cancellation of the Dampier Spirit FSO lease in September 2020.  The revised offtake arrangements in Q4 2020 and through 2021 resulted in a change to the point of sale, with end buyers predominately located in Singapore and Malaysia, which resulted in the Group paying transportation expenses; and

·      A net inventory movement of US$12.5 million (2021: US$9.7 million; 2020: credit of US$2.8 million), reflecting the year-on-year differential of the Group's crude inventories on hand and the change in net underlift/overlift position of the Group at year end due to production imbalances with the joint operating partner in the PenMal Assets.  There were 274,103 bbls on hand at 2021 year end, compared to 601,999 bbls at 2020 year end, contributing to US$9.0 million.  Additionally, the Group has a net underlift of 88,398 bbls from PenMal Assets at year end, compared to 135,115 bbls on the acquisition date, contributing to US$3.5 million.

 

Unit operating costs per barrel of oil equivalent were US$26.22/boe (2020: US$23.10/bbl), before workovers and movement in inventories, but including net lease payments and certain other adjustments (see non-IFRS measures below).  Unit costs increased due to the lower production at Montara and higher operating costs including repairs & maintenance.

 

Depletion, depreciation and amortisation ("DD&A")     

 

DD&A charges were US$80.2 million in 2021, compared to US$84.6 million in 2020, reflecting lower production at Montara during the year, resulting in a decrease in depletion charges in Australia of US$9.0 million compared to 2020.  The reduction was partly offset by depletion charges at the PenMal Assets of US$3.6 million since the date of acquisition of 1 August 2021.

 

Depreciation of the Group's right-of-use assets declined by US$5.0 million mostly due to the termination of the Dampier Spirit leased FSO at Stag in 2020.

 

The depletion cost on a unit basis was US$13.67/boe in 2021 (2020: US$16.24/bbl), predominately due to the inclusion of PenMal Assets which lowered the average DD&A unit charge.  The combined depletion cost on a unit basis at both Stag and Montara remained largely comparable to 2020 (2021: US$16.16/bbl; 2020: US$16.24/bbl).  The PenMal Assets, by comparison, recorded unit depletion charges of US$3.87/boe.

 

Staff costs

 

Total staff costs were US$51.8 million in 2021, comprising US$26.8 million (2020: US$20.7 million) in relation to offshore employees, which are recorded under production costs, and US$25.1 million (2020: US$21.9 million) associated with administrative employees.  The average number of employees employed by the Group during the year was 278 (2020: 210), reflecting the additional employees associated with the acquisition of the PenMal Assets.

 

 

Other expenses

 

Other expenses decreased in 2021 to US$26.2 million (2020: US$26.9 million).  The variance of US$0.7 million was predominately due to:

 

·      Reduction of non-recurring costs by US$9.2 million compared to 2020.  In 2021, the Group incurred total non-recurring costs of US$5.2 million, these included internal reorganisation costs of US$1.1 million, acquisition costs of US$0.8 million in relation to the PenMal Assets, and several other business development related expenses of US$3.3 million.  In comparison, the Group had a total of US$14.4 million of one-off costs in 2020, including US$9.1 million associated with the litigation fees in respect of SC56 and the exit from the Block 05-1 PSC offshore Vietnam (see 'Other income' section for the litigation income generated), Australian rig contract deferral costs of US$3.0 million, Australian exploration expense of US$1.0 million and several business development projects totalling US$1.3 million, including the acquisition of the Lemang PSC;

·      Net foreign exchange loss of US$1.0 million (2020: US$2.6 million);

·      A fair value loss on commodity swaps of US$4.6 million (2020: US$0.5 million) pursuant to the characterisation of the ad-hoc 2021 six-month swap programme as derivative instruments measured at fair value through the profit and loss;

·      Written off of intangible exploration assets of US$5.3 million (2020: nil) following the termination of a contract with a third-party contractor; and

·      Higher provision made for slow-moving materials and spares on hand of US$2.6 million (2020: US$0.1 million), mainly associated with the Australian drilling components and facility spare parts.

 

Other income

 

Other income of US$7.7 million was generated during 2021 compared to 2020 of US$26.4 million.  The income is predominately the result of non-recurring transactions as detailed below:

 

·      During 2021, the Group incurred US$2.5 million of net foreign exchange gains (2020: US$0.1million) associated with the weakening of the Australian dollar;

·      Rebate income of US$4.5 million (2020: US$3.6 million) arising from the sublease of right-of-use assets under the Group's helicopter lease contract;

·      In comparison, during 2020, the Group generated US$11.1 million of litigation income from Total regarding the carried exploration well at SC56 for US11.1 million and received a settlement sum of US$1.0 million from Inpex regarding the litigation resolution of Block 05-1 (see 'Other expenses' section for the litigation fees incurred); and 

·      Also, 2020 saw the reversal of provisions associated with the Dampier Spirit of US$6.4 million and a fair value gain on derivatives of US$3.8 million.

 

Impairment

 

In 2020, the Group recorded an impairment of US$50.5 million associated with the capitalised intangible exploration costs at SC56, as the costs were no longer deemed recoverable, following the decision to voluntarily relinquish the Group's interest in the block. The impairment provision was formally written off during 2021 following the finalisation of the settlement for unfulfilled minimum work commitments under the PSC for US$1.5 million, payable to the Department of Energy in the Philippines.  The penalty was offset against a prior provision of US$1.8 million resulting in a credit to other income of US$0.3 million.

 

Taxation

 

The tax charge of US$14.8 million in 2021 (2020: US$2.9 million) is split between a current tax charge of US$7.3 million (2020: US$11.7 million) and a deferred tax charge of US$7.5 million (2020: credit US$8.7 million).  The current tax charge includes US$9.5 million (2020: nil) of PITA tax incurred by the Malaysian operations, offset by an Australian PRRT refund of US$1.4 million (2020: US$1.7 million paid) and corporate tax credit of US$0.8 million (2020: US$10.0 million expense).

 

 

Australian PRRT

 

Australian petroleum resource rent tax ("PRRT") is a cash-based tax charged at the rate of 40% and is deductible from income tax.  The current tax credit of US$1.4 million is associated with Stag operations, due to the utilisation of PRRT carried forward losses during the year.  Montara is not anticipated to incur PRRT expense in the future, as it has unutilised PRRT carried forward credits of US$3.4 billion (2020: US$3.3 billion).  Based on management's latest forecasts, the augmentation on historical accumulated PRRT net losses will more than offset PRRT that would otherwise arise on future PRRT taxable profits.

 

Malaysian PITA

 

Malaysian petroleum income tax ("PITA") is charged for each year of assessment derived from petroleum operations at the rate of 38%.  The current tax charge represents the tax liability generated from the date of acquisition until the year end.

 

Deferred tax

 

The deferred tax movement during the year reflects timing differences for income tax, PITA and PRRT.  The Group incurred a deferred tax charge of US$7.5 million in 2021, which consists of US$5.2 million for the recognition of net deferred tax liabilities on the Australian operations, US$3.4 million of deferred PRRT expense and US$1.1 million of deferred PITA credit.  In 2020, the Group had a deferred tax credit of US$8.7 million, which consisted of US$4.0 million for the unwinding of deferred tax liabilities and US$4.7 million of deferred PRRT credit.  The increase in deferred tax charge in 2021, compared to 2020, is explained by:

 

·      Additional deferred tax liabilities recognised at the Australian operations, predominately arising from the additional capital expenditure spent at Montara in 2021, which created temporary taxable timing differences arising from the difference between the accounting base and the tax base of oil and gas properties, due to the immediate deductibility of the cost associated with the H6 drilling program.  The Group further recognised deferred tax liabilities arising from the insurance claim receivable of US$10.3 million on the well control claim for the Skua 11 well workovers.  The insurance claim will be taxable in future following cash receipt; 

 

·      Deferred PRRT expense of US$3.4 million in 2021, arising from the reduction of deferred tax assets associated with Stag PRRT, following the utilisation of unutilised PRRT losses carried forward from 2020; and

·      The Group incurred US$1.1 million of deferred PITA credit predominately arising from the recognition of deferred tax assets associated with the oil and gas properties based on the difference between the accounting depletion charge and the tax charge in 2021.

 

 

2021 RECONCILIATION OF NET CASH

 

	US$'000	US$'000
Cash and cash equivalents, 31 December 2020	80,996
Restricted cash, 31 December 2020	8,445
Total cash and cash equivalent, 31 December 2020		89,441
Revenue	340,194
Other operating income	6,030
Production costs	(206,523)
Staff costs	(24,117)
General and administrative expenses	(18,962)
Operating cash flows before movements in working capital		96,622
Movement in working capital		18,808
Net tax paid		(11,834)
Interest paid		(1,505)
Purchases of intangible exploration assets, oil and gas properties, and   plant and equipment1		(55,920)
Net cash inflows from acquisition of PenMal Assets		9,219
Other investing activities		80
Financing activities		(27,046)
Total cash and cash equivalent, 31 December 2021		117,865

 

Net cash increased over the year due to the combination of higher realised prices and increased production due to the acquisition of the PenMal Assets, partially offset by the drilling of the H6 infill development well, spending on the Skua subsea workovers and non-routine repairs and maintenance. 

 

The Group has been debt free following the final repayment of its reserves based loan in March 2021.

 

 

NON-IFRS MEASURES

 

The Group uses certain performance measures that are not specifically defined under IFRS, or other generally accepted accounting principles.  These non-IFRS measures comprise operating cost per barrel of oil equivalent (opex/boe), adjusted EBITDAX, outstanding debt, and net cash.

 

The following notes describe why the Group has selected these non-IFRS measures.

 

 

 

 

¹ Total capital expenditure was US$56.0 million (2020: US$24.1 million), comprising total capital expenditure paid of US$55.9 million (2020: US$17.9 million), plus accrued capital expenditure of US$0.1 million (2020: US$6.1 million).

 

Operating costs per barrel of oil equivalent (Opex/boe)

 

Opex/boe is a non-IFRS measure used to monitor the Group's operating cost efficiency, as it measures operating costs to extract hydrocarbons from the Group's producing reservoirs on a unit basis. 

 

Opex/boe is defined as total production costs excluding oil inventories movement and underlift/overlift, write down of inventories, workovers (to facilitate better comparability period to period) and non-recurring repair and maintenance.  It includes lease payments related to operational activities, net of any income earned from right-of-use assets involved in production, foreign exchange gains arising from foreign exchange forwards in respect of local currency operating expenditure, and excludes transportation costs, PenMal Asset supplementary payments, DD&A and short-term COVID-19 subsidies. 

 

The adjusted production cost  then divided by total produced barrels of oil equivalent for the prevailing period to determine the unit operating cost per barrel of oil equivalent.

 

USD'000 except where indicated		2021		2020
Production costs (reported)		206,523		105,338
Adjustments
Lease payments related to operating activity1		10,619		17,548
Underlift, overlift and crude inventories movement2		(9,680)		2,806
Workover costs3		(67,006)		(21,686)
Impact from FX derivatives apportioned to production costs4		-		(2,649)
Other income5		(4,512)		(3,634)
Non-recurring repair and maintenance6		(6,593)		(1,619)
Australian transportation costs		(1,231)		-
PenMal Assets supplementary payments7		(8,255)		-
Australian Government JobKeeper scheme		196		600
Adjusted production costs		120,061		96,704
Total production (barrels of oil equivalent)		4,578,962		4,186,478
Operating costs per barrel of oil equivalent		26.22		23.10

 

 

 

¹ Lease payments related to operating activities are lease payments considered to be operating costs in nature, including leased helicopters for transporting offshore crews, and the Dampier Spirit FSO rental fees prior to its lease termination in September 2020.  These lease payments are added back to reflect the true cost of production.

² Underlift, overlift and crude inventories movement are added back to the calculation to match the full cost of production with the associated production volumes (i.e., numerator to match denominator).

³ Workover costs are excluded to enhance comparability.  The frequency of workovers can vary significantly, across periods.

⁴ A portion of the net impact from foreign exchange hedging instruments was apportioned to production costs, based on the Group's actual local currency expenditure during the hedging period.

⁵ Other income represents the rental income from a helicopter rental contract (a right-of-use asset) to a third party.

⁶ Non-recurring repair and maintenance costs in 2021 related to the Montara Swift North SCM change out and facility integrity baseline survey.  The costs in 2020 related to costs associated with Cyclone Damien.

⁷ The supplementary payments are required under the terms of PSCs based on Jadestone's entitlement to profit from oil and gas.  The payments are made to PETRONAS.

 

Adjusted EBITDAX

 

Adjusted EBITDAX is a non-IFRS measure which does not have a standardised meaning prescribed by IFRS.  This non-IFRS measure is included because management uses the information to analyse cash generation and financial performance of the Group.

 

Adjusted EBITDAX is defined as profit from continuing activities before income tax, finance costs, interest income, DD&A, other financial gains, non-recurring expenses and exploration assets write-offs.

 

The calculation of adjusted EBITDAX is as follow:

 

USD'000	2021		2020
Revenue	340,194		217,938
Production cost	(206,523)		(105,338)
Administrative staff costs	(25,068)		(21,903)
Impairment of assets	-		(50,455)
Other expenses	(26,181)		(26,918)
Other income, excluding interest income	7,602		26,119
Other financial gains	266		359
Unadjusted EBITDAX	90,290		39,802
Non-recurring
Net loss/(gain) from oil price derivatives	4,633		(30,889)
Impairment of assets	-		50,455
Non-recurring opex1	53,096		8,270
Intangible exploration assets written off	5,260		-
Net litigation income	-		(3,005)
Rig contract deferred costs	-		3,000
Loss/(gain) on contingent considerations	438		(359)
Gain from termination of FSO lease	-		(6,429)
Others2	4,231		1,737
	67,658		22,780
Adjusted EBITDAX	157,948		62,582

 

The Group EBITDAX reflects the strong cash operational performance of the assets with the creation of an additional US$158.0 million generated during 2021 before investing activities and non-recurring operating costs.

 

 

 

 

 

 

¹ Includes one-off major maintenance/well intervention activities, in particular the workover campaigns at Montara Skua 10 & 11, Swift North SCM change out and facility integrity baseline survey in 2021.  The 2020 one-off major maintenance/well intervention activities were comprised of Skua 10 and H3 workover campaigns, and other non-recurring production expenditures such as the repair and maintenance costs associated with weather downtime in 2020. 

² Includes Maari transition team costs, Australian Government JobKeeper scheme, business development and internal reorganisation costs, as well as Montara seismic acquisition costs associated with the non-licence area and gain on contingent consideration in 2020. 

 

Outstanding debt

 

Total borrowings, as recorded in the Group's consolidated statement of financial position, represents the carrying amount of the Group's interest bearing financial indebtedness, measured at amortised cost pursuant to IFRS 9 Financial Instruments.

 

Outstanding debt is a non-IFRS measure which does not have a standardised meaning prescribed by IFRS.  Management uses this measure to manage the capital structure, and make adjustments to it, based on the funds available to the Group.  Outstanding debt is defined as long and short-term interest bearing debt, with effective interest method financing costs added back (i.e., excluded), and excluding derivatives. 

 

As at 31 December 2021, the Group has no outstanding interest bearing financial indebtedness of any kind, following the final scheduled repayment of the RBL at the end of Q1 2021.

 

USD'000		2021		2020
Long-term borrowing		-		-
Short-term borrowing		-		7,296
Add back: effective interest method financing costs		-		1,021
Outstanding debt		-		7,386

 

Net cash

 

Net cash is a non-IFRS measure which does not have a standardised meaning prescribed by IFRS.  Management uses this measure to analyse the financial strength of the Group.  This measure is used to ensure capital is managed effectively in order to support ongoing operations, and to raise additional funds, if required.

 

USD'000		2021		2020
Outstanding debt		-		(7,386)
Cash and cash equivalents		117,865		81,996
Restricted cash		-		7,445
Net cash		117,865		82,055

 

Net cash is defined as the sum of cash and cash equivalents and restricted cash, less outstanding debt.  Cash and cash equivalents in 2021 contain a restricted cash balance of US$0.4 million and US$0.5 million in relation to a deposit placed for bank guarantee with respect to the PenMal Assets and an Australian office building, respectively.  In 2020, restricted cash included the RBL debt service reserve account balance of US$7.4 million but excluded US$1.0 million in respect of a cash collateralised bank guarantee with the Indonesian regulator with respect to a joint study agreement as the guarantee is removable and can then be used to fund the business.  The Indonesian bank guarantee was released in Q3 2021 upon completion of the study.