2023 Half Year Results

 

19 September 2023-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 its unaudited condensed consolidated interim financial statements, as at and for the six-month period ended 30 June 2023 (the "financial statements").  

 

Management will host a conference call at 9:00 a.m. UK time today, details of which can be found in the announcement below.

 

Key updates:

 

l Akatara development project on track to be 65% complete by end-September and remains on budget and schedule for first gas in H1 2024.

l The first well in the four well East Belumut infill drilling programme offshore Malaysia has been drilled successfully and was brought onstream at 2,800 bbls/d gross, significantly ahead of expectations.  The second well in the programme is now underway.

l Montara production has averaged 6,250 bbls/d since early September, benefitting from the return to service of the second production separator and additional wells on the Montara field.

l 2023 production guidance from April to December narrowed to 13,500 - 15,000 boe/d from (13,500 - 17,000 boe/d) reflecting year-to-date production trends and the recent one month shut in at Montara.

l 2023 underlying operating costs guidance expected to come in at lower end of US$180.0 - 210.0 million range, reflecting year-to-date trends and close monitoring of activity levels.

l 2023 capital expenditure guidance is narrowed to US$110.0 - 125.0 million, (from US$110.0 - 140.0 million), primarily reflecting the Akatara development project and East Belumut drilling being on budget.

l US$59.9 million loss after tax for the first half of 2023, consistent with earlier disclosures and reflective of Montara being shut in to late-March 2023 and the subsequent impact on first half liftings.

l Net cash of US$7.8 million at 30 June 2023 reflects c.US$118.8 million of consolidated Group cash balances and US$111.0 million of debt drawn at 30 June 2023 under the Group's reserves-based lending ("RBL") facility.  

 

Paul Blakeley, President and CEO commented:

 

"The first half of 2023 was impacted by the ongoing shut-in of Montara until late March, with few liftings and softer Brent pricing, coincident with a period of heavy investment at Akatara and elsewhere.  We therefore acted decisively to maintain a robust balance sheet by finalising the RBL in May and by raising an additional gross $53 million of new equity in June.  As a result of these actions, we ended the first half in a strong liquidity position which will support the business through Akatara first gas, followed by a rapid return to net cash, likely within the following 12 months period.  Notwithstanding the more recent shut in at Montara, we expect a significantly better financial performance in the second half of 2023, based on our planned lifting schedule, the benefit of recent acquisitions and improved prevailing oil prices.

               

It was disappointing to see Montara shut in again in July, although we quickly identified the source of the defect in one of the FPSO's tanks and restarted production, having implemented a key change to our inspection processes.  This was an important step forward, correcting a small gap in our procedures and giving far greater confidence in the work we are doing to restore the FPSO's condition, resulting in higher uptime reliability at Montara.  It is also important that we take no short cuts, thereby ensuring that safety and structural risks and any potential for a hydrocarbon leak to sea are absolutely minimised.  The provision of a small storage tanker in the near-term enables us to safely continue steady production operations during a period of limited tank capacity on the Montara FPSO, thereby sustaining current production from Montara at around 6,250 bbls/d.

 

I am very proud of the way in which the teams offshore and onshore have worked so tirelessly to restore the condition of the Montara Venture.  We have chosen to adopt inspection levels and processes that are far above industry standards and we will never take short cuts on maintaining asset integrity.     

 

The Akatara project has maintained progress to plan, with an acceleration in recent months as most civil works are now completed, storage tanks are well advanced and many of the long-lead items now arriving at site.  We are on track to be 65% complete by the end of September, for commissioning activities to begin in the first quarter next year, and first gas to be delivered in first half of 2024, as promised.

 

The East Belumut infill drilling campaign commenced in August with pre-drill expectations that the four wells combined will deliver 2 - 2,500 bbls/d of gross production and an IRR of c.90%.  The results of the first well have significantly exceeded our expectations, coming on stream in recent days at c.2,800 bbls/day of dry oil.  We do expect water cut to develop soon and for rates to stabilise nearer 1,000 bbls/d of oil, but the early results are very encouraging.

 

While it has been a difficult few months, we are working hard to restore confidence in our operating model at Montara as well as deliver the growth projects in our portfolio for 2024 and beyond.  The addition of new assets such as CWLH and Sinphuhorm, and new production at Akatara, will increasingly insulate us from one-off events at Montara, but I do believe we have significantly advanced the case for greater reliability across the whole portfolio into the future.  We continue to assess further acquisition opportunities that are consistent with our ambition of delivering growth, ensuring we live within our means of cash flow and debt, and believe we are at a turning point to restore reliability, growth and a strong balance sheet."

 

Paul Blakeley

EXECUTIVE DIRECTOR,

PRESIDENT AND CHIEF EXECUTIVE OFFICER

 

 

2023 FIRST HALF RESULTS SUMMARY

 

USD'000 except where indicated	H1 2023	H1 2022	FY 2022
Production, boe/day1	12,339	15,008	11,487
Realised oil price per barrel of oil equivalent (US$/boe)2	86.15	109.52	103.85
Realised gas price per thousand standard cubic feet     (US$/mscf)	1.41	2.03	1.63
Revenue	86,660	225,639	421,602
Production costs (restated3)	(90,650)	(92,983)	(250,700)
Adjusted unit operating costs per barrel of oil equivalent      (US$/boe)4	40.27	25.71	37.49
Adjusted EBITDAX4 (restated3)	(3,127)	130,930	161,929
(Loss)/Profit after tax (restated3)	(59,934)	43,545	8,522
(Loss)/Earnings per ordinary share: basic and diluted (US$)   (restated3)	(0.13)	0.09	0.02
Operating cash flows before movement in working capital     (restated3)	(24,179)	116,899	158,148
Capital expenditure	23,807	13,621	82,876
Net cash4	7,782	161,628	123,329

 

Operational and financial summary

 

l  Production decreased by 18% year-on-year during H1 2023 to 12,339 boe/d (H1 2022: 15,008 bbls/d), primarily due to the shut-in at Montara between August 2022 to March 2023 resulting in a decrease of 4,578 bbls/d, partly offset by the acquisitions of CWLH Assets adding 1,569 bbls/d and Sinphuhorm at 1,083 boe/d;

l  Oil liftings totalled 1.0 mmbbls in H1 2023 and were 51% lower year-on-year, primarily due to the shut-in at Montara and the later phasing of liftings from the PenMal Assets;

l  The average realised oil price¹ in H1 2023 was US$86.15/bbl, 21% lower than H1 2022, largely due to lower realised Brent prices year-on-year.  The premium achieved in H1 2023 was US$8.87/bbl (H1 2022: US$6.99/bbl) due to relatively high proportion of Stag liftings during H1 2023;

l  H1 2023 revenue totalled US$86.7 million, a 62% decrease on H1 2022, reflecting lower lifted volumes and price realisations as described above;

l  At 30 June 2023, closing crude inventories totalled 421,720 bbls, and the Group had an underlift position of 117,318 bbls.  Post reporting period end, Montara lifted 0.3 mmbbls in mid-July which generated US$24.3 million of revenues;

 

 

l  Production costs decreased by 3% in the period to US$90.7 million (H1 2022: US$93.0 million) predominately due to a credit for inventory changes and lower supplementary payments in Malaysia offsetting the inclusion of CWLH operating costs and higher tanker cost and fuel charges at Stag and Montara;

l  Adjusted EBITDAX decreased to a loss of US$3.1 million (H1 2022: profit of US$130.9 million), mostly due to lower revenues;

l  Net loss after tax in H1 2023 of US$59.9 million (H1 2022: US$43.5 million net profit);

l  Operating cash outflow before movements in working capital in H1 2023 of US$24.2 million (H1 2022: cash inflows of US$116.9 million), reflecting the trends described above;

l  Capital expenditure in H1 2023 of US$23.8 million, an increase of 75% compared to H1 2022 primarily due to the ramp up of activities at the Akatara development project onshore Indonesia; and

l  Net cash balance of US$7.8 million as at 30 June 2023 (H1 2022: US$161.6 million), reflecting the operating cash outflows during H1 2023, drawdown of the Group's reserves-based loan and the proceeds from the equity placing and open offer in June 2023.

 

Significant events

 

l  On 19 January 2023, the Group executed a sale and purchase agreement with Salamander Energy (S.E. Asia) Limited (the "Seller"), an affiliate of PT Medco Energi Internasional Tbk, to acquire the Seller's 9.52% non-operated interest in the producing Sinphuhorm gas field and a 27.2% interest in the Dong Mun gas discovery onshore northeast Thailand (the "Sinphuhorm Assets");

l  On 17 February 2023, the Group closed a US$50.0 million debt facility ("Interim Facility") with two international banks to provide additional liquidity prior to closing the reserves-based lending facility ("RBL").  The loan was fully repaid on 1 June 2023;

l  On 22 May 2023, the Group announced the closing of a US$200.0 million RBL facility with a group of four international banks (the "RBL Banks").  The first drawdown of US$111.0 million occurred in June and was used to repay the Interim Facility and to fund the Group's operations and capital investment programme;

l  As required by the RBL facility, at 30 June 2023, the Group had entered into oil price swap contracts for 4.2 mmbbls, representing approximately 78% of the required hedging volumes, at a weighted average price of US$70.29/bbl.  The hedging programme was subsequently completed in July 2023, with  5.5 mmbbls hedged over the Q4 2023 to Q3 2025 period at an overall weighted average price of US$70.57/bbl; and

l  On 6 June 2023, the Company raised US$51.1 million (net of costs) through an equity placing and open offer of 94,081,826 ordinary shares at a price of £0.45 per share.  The offer was underwritten by Tyrus Capital Events S.a.r.l. ("Tyrus"), the Company's largest shareholder.  In connection with the underwriting, Tyrus received warrants for 30 million ordinary shares with an exercise price of £0.50 per share and exercisable any time within 36 months from the date of issue.  In addition, the Company entered into a standby working capital facility agreement with Tyrus to provide financial flexibility and balance sheet resilience.  The standby working capital facility closed at US$31.9 million and has an expiry date of 31 December 2024.  The standby working capital facility remains undrawn.

 

2023 Guidance

 

l  Production: Guidance for the period April to December 2023 is narrowed to 13,500 - 15,000 boe/d (from 13,500 - 17,000 boe/d), reflecting year-to-date trends in production and the recent one month shut in at Montara.  The revised range for April to December 2023 is equivalent to an annual 2023 guidance range of 12,600 - 13,700 boe/d;

l  Operating costs: Underlying operating costs are expected to come in at the lower end of the US$180.0 - 210.0 million guidance range, reflecting year-to-date trends and close monitoring of activity levels.  As disclosed previously, underlying operating cost guidance excludes non-recurring items and certain costs such as workovers, transportation, and expenditure associated with non-producing assets offshore Malaysia.  These excluded items are included in the reported production costs in the Group's statement of profit or loss, and are expected to total US$65.0 - 75.0 million in 2023; and

l  Capital expenditure: Capital expenditure guidance is narrowed to US$110.0 - 125.0 million (from US$110.0 - 140.0 million), reflecting expenditure at the Akatara development project and the East Belumut drilling campaign progressing in line with plan, along with some rephasing of spend on projects across the Group's portfolio.  Capital expenditure guidance excludes abandonment expenditure associated with the PNLP Assets offshore Malaysia, which is expected to total c.US$15.0 million in 2023.  This figure is expected to be partially recovered through existing cess funds in 2024.

 

¹ Production includes the Sinphuhorm Asset gas production in accordance with Petroleum Resource Management Systems guidelines, however in accordance with IAS 28 the investment is accounted for as an associated undertaking and only recognises dividends received.  Accordingly, the revenue and production costs from the Sinphuhorm Assets are excluded from the Group's financial results.  Sinphuhorm production is included in the Group's production figures.

² Realised oil price represents the actual selling price inclusive of premiums.

³ Certain H1 2022 comparative information has been restated.  Please refer to Note 25 in the unaudited condensed consolidated interim financial statements.

⁴ Adjusted unit operating costs per boe, adjusted EBITDAX and net cash are non-IFRS measures and are explained in further detail on the Non-IFRS Measures section in this document.

 

Enquiries

 

Jadestone Energy plc.
Paul Blakeley, President and CEO	+65 6324 0359 (Singapore)
Bert-Jaap Dijkstra, CFO
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 / Andrew Turner / Elfie Kent	[email protected]

 

Conference call and webcast

The Company will host an investor and analyst presentation at 9:00 a.m. (BST) on Tuesday, 19 September 2023, including a question-and-answer session, accessible through the link below:

 

Webcast link: https://www.investis-live.com/jadestone-energy/64e4883e0120c60d001e4a75/avdt  

 

Event title: Jadestone Energy plc first-half 2023 results

Time: 9:00 a.m. (BST)

Date: 19 September 2023

 

To join the presentation by phone, please use the below dial-in details from the United Kingdom or the link for global dial-in details:

 

United Kingdom (Local): +44 20 3936 2999

United Kingdom (Toll-Free): +44 800 358 1035

Global Dial-In Details: https://www.netroadshow.com/events/global-numbers?confId=54821

Access Code: 399289

 

 

ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG")

 

As a responsible upstream operator, Jadestone contributes to an orderly energy transition by helping to meet regional Asia-Pacific energy demand from existing, discovered resources, whilst minimising the environmental footprint of its operations.  Jadestone believes that this strategy allows it to play an important role in the energy transition - as larger oil and gas companies divest their mid-life assets, Jadestone is well positioned to be the steward of those assets through to the end of field life.  In doing so, Jadestone aims to bring positive social and economic benefits for its stakeholders, local communities and people associated with its operations.

 

Jadestone published its fourth Sustainability Report in June 2023, which covered the Group's ESG performance in 2022.  The section below provides an overview of H1 2023 performance of the Group, representing the Stag and Montara fields, the PenMal operated and producing assets and, where relevant, the Akatara gas development.  

 

Net Zero and GHG emissions

 

The Group pledged in June 2022 to achieve Net Zero Scope 1 and 2 GHG emissions from its operated assets by no later than 2040.  The detail of this pledge, as well as Jadestone's strategy through the energy transition, can be found on Jadestone's website¹.  The Group is on track to publish its Net Zero roadmap by the end of 2023 as it progresses feasibility studies for the shortlisted GHG reduction options at its operated assets.  In H1 2023, a concept selection study was completed to evaluate options available in the market to increase gas handling capacity of the compression systems at one of the PenMal sites.  A business case was submitted to Jadestone's partner in Malaysia to seek approval for this project, which is currently planned for implementation in H1 2025.  Similarly, a feasibility study of possible ways of increasing the compression capacity at the Montara venture was undertaken, with further trials being planned to determine next steps. Both initiatives illustrate the Group's focus on minimising its flaring related GHG emissions whilst maximising oil recovery.  

 

HSE performance

 

The Group's priority remains the health and safety of its staff and contractors, along with ensuring that any negative environmental impacts from operations are minimised. 

 

The Group reported zero recordable incidents during the first half of 2023, and zero lost time injuries at the operated assets and project sites.  Of note, the Akatara gas development has reported more than 1.9 million manhours without a recordable injury, which contributed to the Group's seventh month without recordable injury.  Four high-potential events were recorded across the Group in the period.  The Group ensures that such events are thoroughly investigated and corrective actions shared to ensure learning and minimise the probability of reoccurrence.

 

Process safety continues to be a focus area, with zero Tier 1 loss of primary containment (LOPC) events reported during H1 2023.

 

With respect to environmental performance, the Group recorded zero releases to the environment.  On the Montara Venture FPSO, a phased production restart campaign commenced in March 2023.  The Group has progressed with the work related to the FPSO's cargo tank integrity, with phase 2 inspections progressing well. In February 2023, the Group has announced that the General Direction issued by the industry regulator, NOPSEMA, was closed, following NOPSEMA's review of an independent assessment focusing on Jadestone's systems for managing the structural integrity of the Montara Venture FPSO.

 

Governance

 

Following an external review of the Board's performance during 2022, the Board is implementing a number of the recommendations resulting from the review, to further ensure that the Group's governance structure continues to improve, supporting the delivery of strategy and the longer-term success of the Group.  Acting on the recommendations of the independent party has resulted in greater direct dialogue amongst the Board, employees, shareholders and other stakeholders, further strengthening Jadestone's alignment with the principles of the QCA Code.

 

As previously reported, the Board believes that certain changes are necessary to refresh its composition and adhere to best practice by adding new experience to bolster the overall governance framework of the Company.  Two of the board's longest serving directors, Iain McLaren, Independent Non-Executive Director and Chair of the Audit Committee (who has served since 2015) and Robert Lambert, Independent Non-Executive Director, Deputy Chairman and Chair of the Health, Safety, Environment and Climate Committee (who has served since 2011), have signalled their intention to step down, once replacements have been appointed.

 

Furthermore, the Board and management team of Jadestone have concluded that, given the significant growth and diversification of the Group's operations in recent years, it is appropriate to strengthen the senior management team and enhance internal succession planning options by creating the role of Chief Operating Officer (COO).  A search for the new Non-Executive Directors and the COO is well underway, with the current expectation that these positions will be filled by early 2024.

 

 

¹ https://www.jadestone-energy.com/jadestone-announces-2040-net-zero-target/

 

As disclosed on page 53 of the 2022 Annual Report, the Group commenced its second and final phase of the internal reorganisation which started in 2022.  This phase of internal reorganisation involves moving the Group's business activities from Canadian sub-holding entities to a Singapore registered sub-holding entity.  The Group does not carry out any business activity in Canada, nor it is not planning to in the future.  The relevant intra-group organisational changes are being executed at arm's length using third-party expert advice, and will be completed in 2023.

 

 

OPERATIONAL REVIEW

 

Producing assets

 

Australia

 

Montara project

 

Montara production averaged 2,931 bbls/d for the first half of 2023 (H1 2022: 7,509 bbls/d). 

 

There was one lifting during H1 2023 resulting in total sales of 0.2 mmbbls, compared to 1.3 mmbbls from three liftings during H1 2022.  The premium realised in H1 2023 was US$1.36/bbl (H1 2022: US$4.52/bbl).  A further lifting was completed post-period in July 2023 for 0.3 mmbbls with a premium of US$2.01/bbl.

 

The Montara fields were shut in between August 2022 to March 2023 for storage tank inspection, maintenance and repair work following a small release of oil to sea in June 2022 and a further tank defect encountered in August 2022.

 

Following lifting of the General Direction issued by NOPSEMA in September 2022 and the completion of tank inspection and repair activities, as well as scheduled four-yearly maintenance activities, a phased production restart campaign commenced in late-March 2023.  From restart up to 29 July 2023, Montara production averaged approximately 6,100 bbls/d, with a maximum rate of 8,100 bbls/d.

 

On 29 July 2023, production at Montara was temporarily shut in following a hydrocarbon gas alarm in ballast water tank 4S.  Inspections identified the location of a small defect between tank 4S and oil cargo tank 5C, with repairs currently in progress.  Ballast water tank 4P was returned to service in early September 2023 following minor repairs.

 

Production restarted on 1 September 2023 and subsequently ramped up to c.8,000 bbls/d (including flush production) after restart of the FPSO's gas compression system.  The field is currently producing 6,250 bbls/d, benefitting from the recent return to service of the second production separator and Montara H2, H3 and H4 wells.

 

Stag oilfield

 

Production during H1 2023 was 2,879 bbls/d, compared to 2,057 bbls/d during H1 2022, with the increase due to the successful completion and contribution of the 50H and 51H wells drilled in November 2022. 

 

There were two liftings during H1 2023, resulting in total sales of 0.5 mmbbls, compared to 0.3 mmbbls in H1 2022 from one lifting.  The premiums realised in H1 2023 were US$19.10/bbl and US$12.66/bbl, with an average premium of US$16.11/bbl (H1 2022: US$23.72/bbl).  The most recent Stag lifting in August 2023 realised a premium of US$10.10/bbl.

 

North West Shelf Project

 

Production during H1 2023 was 1,569 bbls/d net to Jadestone's working interest.  There was no comparable production in H1 2022 as the acquisition of the CWLH Assets was completed in November 2022.  Production net to Jadestone was 2,290 bbls/d between 1 November and 31 December 2022 and decreased in H1 2023 due to unplanned downtime and a temporary shut-down of the FPSO due to Cyclone Ilsa.

 

Jadestone's next lifting is expected in Q4 2023.

 

Malaysia

 

PM 323, PM329, PM318 and AAKBNLP PSCs

 

During H1 2023, average production from the PM323 and PM329 PSCs was 3,185 bbls/d of oil and 4,158 mscf/d of gas, creating a combined production of 3,878 boe/d, net to Jadestone's working interest (H1 2022: 4,578 bbls/d of oil, 5,191 mscf/d of gas, combined production of 5,443 boe/d).  The decrease in production was predominately associated with natural field decline and higher unplanned downtime as a result of the temporary closure of the Chermingat platform due to operational issues.

 

There were three oil liftings during H1 2023, for total sales of 0.3 mmbbls in addition to the sale of 752.7 mmscf of gas, compared to seven oil liftings during H1 2022, for total sales of 0.5 mmbbls and sale of 939.7 mmscf of gas.  The premium in H1 2023 ranged between US$2.72/bbl and US$4.68/bbl with an average realised premium of US$3.53/bbl.  The latest liftings during July and August 2023 have achieved premiums of US$3.24/bbl and US$4.19/bbl, respectively.

 

There was no production from the PM318 and AAKBNLP PSCs (the "PNLP Assets") as facilities remained shut-in since the class suspension of the Bunga Kertas FPSO in February 2022.  In April 2023, the Group assumed operatorship of the PNLP Assets following the decision of the previous operator to withdraw from the licences.  The Group believes there may be significant remaining reserves on the licences and is evaluating redevelopment options for the PSCs.  The Group submitted a Business Value Proposition ("BVP") on 30 June 2023 for PETRONAS's approval.  The BVP includes an overview of the Group's plan of activities to reinstate production from the PNLP Assets.  If and when approved, the Group will commence negotiation with PETRONAS on the PSC fiscal terms and may subsequently seek Jadestone Board's approval prior to sanctioning the project.

 

Thailand

 

APICO LLC (Sinphuhorm gas field and Dong Mun gas discovery)

 

On 19 January 2023, the Company announced the execution of the sale and purchase agreement with Salamander Energy (S.E. Asia) Limited, an affiliate of PT Medco Energy Internasional Tbk, to acquire the Seller's interest in three legal entities, which collectively own a 9.52% non-operated interest in the producing Sinphuhorm gas field and a 27.2% interest in Dong Mun gas discovery onshore north-east Thailand.  The acquisition included a 27.2% interest in APICO LLC, which operates the Sinphuhorm concessions (E5N and EU1) and Dong Mun (L27/43).  Due to a lack of influence over the day-to-day operational activities at the Sinphuhorm Assets, the Group does not recognise its share of revenues and production costs, instead recognising dividend income when received from APICO LLC.  There was no dividend received during H1 2023.  The acquisition closed on 23 February 2023 for a cash consideration of US$27.8 million, based on an effective date of 1 January 2022.

 

The acquisition added 4.6 mmboe of total proved plus probable reserves, net to Jadestone, at the effective date of 1 January 2022.

 

Average production since the date of acquisition was 1,531 boe/d, equating to 1,083 boe/d for H1 2023.

 

 

 

 

Pre-production assets

 

Indonesia

 

Akatara field, 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, and three years of oil production history, up until the field ceased oil production in December 2019.  Jadestone is redeveloping Akatara field to supply gas, condensate and LPGs for local and regional use.

 

The Akatara gas field has been independently estimated to contain gross 2P reserves (before taking into account the local government back-in right) of 71.1 bcf of sales gas, 2.2 mmbbls of condensate and 8.4 mmboe of LPG, equating to a combined 22.5 mmboe of resource.  Jadestone has 100% interest in the Lemang PSC, with the local government retaining a back-in right of up to 10%, which is expected to be exercised prior to first gas.

 

Activity during the first half of 2023 focused primarily on preparatory and civil works at the Akatara Gas Processing Facility ("AGPF").  The AGPF project is on track to be 65% complete by end of September, and is currently focusing on major equipment installation and integration with piping, and electrical instrumentation.  Key long-lead items have started to arrive at site which will continue through November 2023.  Commissioning activities are expected to commence in Q1 2024 with commercial production before the end of H1 2024.

 

In June 2023, the Group completed the successful reactivation of two wells, the Akatara-1 (A1) and BWI-1 wells.  Both wells were reactivated from suspension status, with a production test at A1 and waste brine injection operation at BWI-1.  The A1 well flowed at a maximum rate of c.9 mmcf/d, with data from the well test underpinning the current Akatara 2P reserves estimate.  The A1 well will provide pre-commissioning and commissioning gas for the AGPF and BWI-1 is also ready to be utilised as an injector/disposal well.  A workover campaign for four wells is on schedule for Q4 2023 to Q1 2024 to deliver the gas production required to meet the daily contract quantity under the gas sales agreement.

 

Vietnam

 

Block 51 and Block 46/07 PSCs

 

During the first half of 2023, the Group continued to negotiate a heads of agreement for gas sales from the Nam Du/U Minh development project.  Following a gas sales agreement, the Group would work to finalise the field development plan and submit this for approval - a key step towards commercialising this significant and strategic resource.  In early August 2023, Jadestone's Chief Executive Officer met with Vietnam's Prime Minister, who expressed encouragement for Jadestone's development of the Nam Du/U Minh fields and directed relevant stakeholders to support Jadestone on progressing the development of the fields.  Development of the Nam Du/U Minh resource would help reduce energy shortages in Vietnam, lessen future dependence on expensive LNG imports and would contribute towards the country's energy transition and stated goal of Net Zero greenhouse gas emissions by 2050.

 

 

 

 

 

FINANCIAL REVIEW

 

The following table provides selected financial information of the Group, which was derived from, and should be read in conjunction with, the unaudited condensed consolidated interim financial statements for the period ended 30 June 2023.

 

USD'000 except where indicated	Six months ended 30 June 2023	Six months ended 30 June 2022	Twelve months ended 31 December 2022
Sales volume, barrels of oil equivalent (boe)	1,119,011	2,199,583	4,326,770
Production, boe/day1	12,339	15,008	11,487
Realised oil price per barrel of oil equivalent (US$/boe)2	86.15	109.52	103.85
Realised gas price per thousand standard cubic feet   (US$/mscf)	1.41	2.03	1.63
Revenue	86,660	225,639	421,602
Production costs (restated3)	(90,650)	(92,983)	(250,700)
Adjusted unit operating costs per barrel of oil equivalent,   (US$/boe)4	40.27	25.71	37.49
Adjusted EBITDAX4 (restated3)	(3,127)	130,930	161,929
Unit depletion, depreciation & amortisation (US$/boe)	13.15	12.06	10.80
Impairment of assets	-	-	(13,534)
(Loss)/Profit before tax (restated3)	(70,275)	77,671	62,540
(Loss)/Profit after tax (restated3)	(59,934)	43,545	8,522
(Loss)/Earnings per ordinary share: basic and diluted (US$)   (restated3)	(0.13)	0.09	0.02
Operating cash flows before movement in working capital   (restated3)	(24,179)	116,899	158,148
Capital expenditure	23,807	13,621	82,876
Net cash4	7,782	161,628	123,329

 

Benchmark commodity price and realised price

 

The average realised oil price decreased in H1 2023 by 21% to US$86.15/bbl, compared to US$109.52/bbl during H1 2022. 

 

The primary driver of the decrease in the H1 2023 realised oil price was the benchmark Brent price, which fell by 25% to US$77.28/bbl, compared to H1 2022 at US$102.53/bbl.  The average realised premium for the period was US$8.87/bbl, compared to H1 2022 of US$6.99/bbl, due to the composition of liftings between the periods, as H1 2023 contained relatively higher volumes of Stag crude oil with a realised premium of US$16.11/bbl compared to the realised premium of Montara with US$1.36/bbl.

 

 

 

 

 

¹ Production includes the Sinphuhorm Asset gas production in accordance with Petroleum Resource Management Systems guidelines, however in accordance with IAS 28 the investment is accounted for as an associated undertaking and only recognises dividends received.  Accordingly, the revenue and production costs from the Sinphuhorm Assets are excluded from the Group's financial results.  Sinphuhorm production is included in the Group's production figures.

² Realised oil price represents the actual selling price inclusive of premiums.

³ Certain H1 2022 comparative information has been restated.  Please refer to Note 25 in the unaudited condensed consolidated interim financial statements.

⁴ Adjusted unit operating cost per boe, adjusted EBITDAX and net cash are non-IFRS measures and are explained in further detail on the Non-IFRS Measures section in this document.

 

Production and liftings

 

The average production for the period was 12,339 boe/d, compared to 15,008 boe/d in H1 2022.  The overall decrease of 2,669 bbls was the result of the following factors:

·      Lower production (4,578 bbl/d) at Montara due to the shutdown between August 2022 to March 2023;  and

·      Decreased production (1,565 boe/d) from the PenMal Assets due to higher unplanned downtime of the Chermingat platform and natural field decline. 

 

The above decrease was partly offset by:

·      A full period of the CWLH Assets contributing 1,569 bbls/d;

·      Sinphuhorm Assets contributing an average of 1,083 boe/d from closing of the acquisition in February 2023; and 

·      Stag production increased by 822 bbls/d due to the additional production generated from successful drilling and completion of 50H and 51H wells in November 2022. 

 

There were six liftings during the period (H1 2022: 11), resulting in sales of 1.0 mmbbls (H1 2022: 2.0 mmbbls).  Lifted volumes were lower predominately due to the shut-in at Montara, which recorded one lifting in H1 2023 for 0.2 mmbbls, compared to 1.3 mmbbls from three liftings in H1 2022. 

 

Stag recorded 0.5 mmbbls of liftings, compared to 0.3 mmbbls in H1 2022.

 

PenMal Assets recorded 0.3 mmbbls of liftings in addition to the sale of 752.7 mmscf of gas, compared to 0.5 mmbbls and sale of 939.7 mmscf of gas in H1 2022.

 

Revenue

 

The Group generated US$86.7 million of revenue in H1 2023, compared to US$225.6 million during H1 2022, a decrease of 62%.  The decrease of US$139.0 million is due to:

 

·      Lower lifted volumes between the period generating a decrease of US$90.4 million;

·      Lower average realised oil prices of US$86.15/bbl (H1 2022: US$109.52/bbl), contributing to a decrease of revenue by US$47.7million; and

·      US$0.8 million lower gas sales at the PenMal Assets due to natural field decline.

 

Production costs

 

Production costs in H1 2023 were US$90.7 million (H1 2022: US$93.0 million), a decrease of US$2.3 million predominately due to a higher credit to production costs of US$16.1 million, lower supplementary payments by US$11.5 million and lower operating costs by US$6.5 million in the PenMal Assets.  The decrease in production costs was partly offset by higher operating costs of US$26.4 million incurred at Montara, Stag and the CWLH Assets.  A more detailed breakdown is provided below:

 

·      Closing inventory and underlift movements during H1 2023 generated a credit to production cost of US$24.9 million (H1 2022: US$8.8 million).  Montara and Stag had combined higher crude inventories (H1 2023: increased by 331,039 bbls; H1 2022: increased by 143,113 bbls) compared to the beginning of respective periods, thus generating a credit of US$14.7 million (H1 2022: US$8.5 million).  The underlift at the CWLH Assets further generated a credit to production costs of US$10.1 million, as costs are matched against lifting, which is scheduled for Q4 2023;

·      Supplementary payments and royalties decreased by US$10.3 million to a total of US$7.3 million, compared to US$17.6 million in H1 2022.  The supplementary payments at the PenMal Assets decreased by US$11.5 million to US$5.5 million (H1 2022: US$17.0 million) due to the lower realised price compared to H1 2022 with the payments based on the differential between the realised price and the escalated PSC base price.  The decrease was partly offset by US$1.4 million of royalties paid by the CWLH Assets for the levy on the wellhead value for a primary production licence (H1 2022: nil);

·      PenMal Assets operating costs reduced by US$6.5 million to US$2.8 million (H1 2022: US$9.3 million) following the production suspension since February 2022 at the PNLP Assets.  Operating costs at PM323 and PM329 PSCs were stable comparing period-to-period;

 

 

·      Operating costs at Montara and Stag increased by US$17.8 million to US$41.1 million in H1 2023, compared to US$23.3 million in H1 2022, with additional costs of US$6.1 million incurred at Montara related to the hire of a crude tanker to compensate for reduced FPSO tank capacity, and an additional US$5.0 million for higher diesel consumption to power the compressor system during shutdown of the FPSO's gas train.  Stag tanker costs increased by US$5.9 million compared to H1 2022 reflecting higher tanker rates in H1 2023;

·      The CWLH Assets contributed an US$8.6 million increase in production cost for H1 2023 compared to the same period last year as the acquisition was completed in November 2022; and

·      Repair and maintenance ("R&M") costs increased by US$3.1 million to a total of US$28.4 million, compared to US$25.3 million in H1 2022.  The PenMal Assets incurred a total of US$6.8 million (H1 2022: US$2.7 million) mostly reflecting the demobilisation work on the FPSO at the PNLP Assets, repair work at the PM323 PSC Chermingat platform during the temporary shutdown and the repair of the gas turbine generator at PM329 PSC.  This increase was partly offset by US$1.0 million lower R&M costs incurred by the Australian assets.

                                                                                                                                                      

Adjusted unit operating cost per boe was US$40.27/bbl (H1 2022: US$25.71/boe) (see Non-IFRS measures section below in this document).  The increase in adjusted unit operating cost is mostly caused by the reduced production during the period at Montara and the PenMal Assets combined with the increased tanker rates at Stag during H1 2023.

 

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

 

The depletion charges of oil and gas properties were US$24.6 million in H1 2023, compared to US$35.1 million in H1 2022, predominately due to the lower production at Montara.  As a result, the PenMal Assets and Stag represented a higher proportion of production.  The DD&A rate at Montara was US$23.64/bbl (H1 2022: US$19.46/bbl) compared to Stag at US$19.05/bbl (H1 2021: US$12.72/bbl) and PenMal US$1.49/bbl (H1 2022: US$1.61/bbl).

 

The depletion cost on a unit basis in H1 2023 was US$13.15/boe, 9% higher when compared to US$12.06/boe in H1 2022, mostly due to an increase in the asset retirement obligations ("ARO") and the addition of capital expenditure from drilling of the 50H and 51H wells at Stag in Q4 2022.

 

Depreciation of the Group's right-of-use assets increased to US$7.0 million in H1 2023 from US$6.1 million in H1 2022, primarily due to the three-year lease extension for helicopters at Montara which commenced in April 2023.

 

Other expenses

 

Other expenses increased during H1 2023 to US$8.4 million (H1 2022: US$5.5 million).  The increase of US$2.9 million was predominately related to advisory and consulting fees for business development and the earlier reported internal reorganisation.

 

Finance costs

 

Finance costs in H1 2023 were US$22.5 million (H1 2022: US$4.8 million), an increase of US$17.7 million, predominately due to:

 

·      Warrants expense of US$6.1 million arose from the warrants for 30 million ordinary shares received by Tyrus in connection with the underwriting debt facility in support of the equity placing;

·      ARO accretion expense increased by US$5.4 million to US$9.6 million compared to US$4.2 million in H1 2022, resulting from an increase in the ARO at Stag and Montara as assessed at year-end 2022.  The Group also incurred US$0.2 million of accretion expense on Lemang PSC long-term VAT receivables;

·      Interest expense increased by US$2.6 million to US$2.7 million compared to US$0.1 million in H1 2022, mainly due to the interest expense and fees associated with the US$50.0 million Interim Facility (US$1.3 million) and relating to the RBL facility (US$1.2 million).  In addition, an upfront fee of US$2.2 million was paid for the equity underwrite debt facility agreement (H1 2022: nil);

·      Interest on lease liabilities increased by US$0.6 million to US$1.0 million compared to US$0.4 million in H1 2022, mainly due to the three-year lease extension for helicopters at Montara which commenced in April 2023; and

 

 

·      Lemang PSC contingent payments contributed US$0.5 million relating to the accretion of the present value of the liability.

 

Taxation

 

The tax credit of US$10.3 million in H1 2023 (H1 2022: tax charge of US$34.1 million) includes a current tax credit of US$2.1 million (H1 2022: tax charge of US$34.9 million) and a deferred tax credit of US$8.2 million (H1 2022: US$0.8 million). 

 

The tax paid during the period included US$1.3 million of corporate tax payments and US$3.4 million of petroleum income tax ("PITA") tax in Malaysia.

 

The weighted average effective tax rate based on the countries where the producing assets are located was 56% (H1 2022: 56%).  The consolidated group effective tax rate for the current period was negative 15% (H1 2022: 44%) reflecting the Group's loss making position. 

 

Australia taxes

 

The Australian corporate income tax rate is 30% and Petroleum Resource Rent Tax ("PRRT") is 40%, which is cash based and income tax deductible.  The combined standard effective tax rate is 58%, while the actual effective tax rate for the current period is negative 27% due to the combined net losses incurred from the Australian operations, which predominately arose from the production shut-in at Montara.  The Australian operations recognised a current tax credit of US$2.1 million relating to an overprovision of tax expense in 2022.  Additionally, a deferred tax credit of US$8.8 million was recognised reflecting the loss incurred during H1 2023 which can be carried forward to offset future taxable profits.

 

Stag recognised a deferred PRRT tax credit of US$0.2 million due to PRRT credits available from the augmentation¹ in H1 2023, which can be utilised to offset future PRRT expense.

 

Malaysia taxes

 

Malaysian PITA is a PSC based tax on petroleum operations at the rate of 38%.  There are no other material taxes in Malaysia.  The PenMal Assets incurred a deferred PITA charge of US$0.8 million which primarily arose from the timing differences of the accounting and tax bases of the oil and gas properties.

 

 

 

¹ The PRRT credits were generated from the capital expenditure incurred in Australia.  The unutilised PRRT credits are augmented (increased with inflation) at a rate approved by the Australian Tax Office.

 

RECONCILIATION OF CASH

 

US$'000	H1 2023		H1 2022
Cash and cash equivalent at the beginning of   period		123,329		117,865
Revenue	86,660		225,639
Other operating income	3,324		3,528
Production costs (restated1)	(90,650)		(92,983)
Administrative staff costs	(15,080)		(14,482)
Other expenses	(8,433)		(4,803)
Operating cash flows before movements in   working capital		(24,179)		116,899
Movements in working capital (restated1)		(30,377)		(12,907)
Net tax paid		(4,755)		(34,177)
Purchases of intangible exploration assets, oil and   gas properties, and plant and equipment2		(23,439)		(13,364)
Cash paid for acquisition of Sinphuhorm Assets		(27,853)		-
Placement of decommissioning trust fund for   CWLH Assets		(41,000)		-
Placement of abandonment cess fund for PenMal   Assets		-		(169)
Other investing activities		1,466		170
Net proceeds from issuance of shares		51,070		670
Shares repurchased		(2,084)		-
Dividend paid		-		(6,241)
Repayment of lease liabilities		(7,009)		(6,518)
Total drawdown from borrowings		161,000		-
Repayment of borrowings		(50,000)		-
Financing activities		(7,387)		(600)
Total cash and cash equivalent at the end of   period		118,782		161,628

 

 

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 adjusted unit operating cost per barrel of oil equivalent (adjusted opex/boe), adjusted EBITDAX, outstanding debt, and net cash.

 

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

 

Adjusted unit operating costs per barrel of oil equivalent (Adjusted opex/boe)

 

Adjusted 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. 

 

 

 

 

¹ Certain H1 2022 comparative information has been restated.  Please refer to Note 25 in the unaudited condensed consolidated interim financial statements.

² Total capital expenditure was US$23.8 million (H1 2022: US$13.6 million), comprising total capital expenditure paid of US$23.4 million (H1 2022: US$13.4 million) and accrued capital expenditure of US$0.4 million (H1 2022: US$0.2 million).

 

Adjusted 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, and excludes transportation costs, PenMal Asset supplementary payments, costs associated with the PenMal non-operating assets and DD&A. 

 

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

 

		Six months ended		Six months ended		Twelve months ended
USD'000 except where indicated		30 June 2023		30 June 2022		31 December 2022
Production costs (reported) (restated1)		90,650		92,983		250,700
Adjustments
Lease payments related to operating activities2		7,493		6,371		13,687
Underlift, overlift and crude inventories   movement3 (restated1)		24,897		8,830		(39,436)
Workover costs4		(9,531)		(8,435)		(10,190)
Other income5		(2,584)		(2,410)		(5,030)
Non-recurring operational costs6		(11,565)		-		-
Non-recurring repair and maintenance7		(312)		(5,510)		(13,761)
Transportation costs		(3,035)		(510)		(8,341)
PenMal Assets supplementary payments and   Australian royalties8		(7,298)		(16,731)		(26,381)
PenMal non-operated assets operational costs9		(6,670)		(4,748)		(4,056)
Adjusted production costs		82,045		69,840		157,192
Total production (barrels of oil equivalent)		2,037,420		2,716,436		4,192,618
Adjusted unit operating costs per barrel of oil   equivalent		40.27		25.71		37.49

                                                                                                                                                                                         

 

¹ Certain H1 2022 comparative information has been restated.  Please refer to Note 25 in the unaudited condensed consolidated interim financial statements.

² Lease payments related to operating activities are lease payments considered to be operating costs in nature, including leased helicopters for transporting offshore crews.  These lease payments are added back to reflect the true cost of production.

³ 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).

⁴ Workover costs are excluded to enhance comparability.  The frequency of workovers can vary significantly, across periods.

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

⁶ Non-recurring operational costs in H1 2023 mainly related to costs incurred at Montara being interim tanker storage temporarily employed as a result of the repair work relating to the storage tanks of the FPSO, diesel fuel consumption by the FPSO during production shutdown and to power the reinjection compressor during production start-up.  The Group also incurred charges associated with short lifting a cargo and delivery delays.

⁷ Non-recurring repair and maintenance costs in H1 2023 predominately related to the repair of a gas turbine generator at the PenMal Assets PM329 PSC.  The costs during H1 2022 predominately related to Montara Skua-11 well subsurface repairs and Stag structural marine maintenance and import hose replacement.

⁸ The supplementary payments are required under the terms of PSCs based on Jadestone's profit oil after entitlements between the government and joint venture partners.  The Australian royalties include a temporary levy passed by the Australian Government on offshore petroleum production and a levy on the wellhead value of primary production licence from the CWLH Assets.

 

⁹ PenMal non-operated assets operational costs in H1 2023 refer to the operating costs incurred at the PNLP Assets, which are excluded as the costs incurred were mainly related to the preservation of facilities and subsea infrastructure and don't contribute to production.   The costs in 2022 predominately related to the costs incurred to repair the FPSO BUK at the PNLP Assets following the suspension of class in February 2022.

 

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 measure to analyse cash generation and financial performance of the Group.

 

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

 

The calculation of adjusted EBITDAX is as follow:

 

	Six months ended		Six months ended		Twelve months ended
USD'000	30 June 2023		30 June 2022 Restated1		31 December 2022
Revenue	86,660		225,639		421,602
Production costs (restated1)	(90,650)		(92,983)		(250,700)
Administrative staff costs	(15,538)		(15,165)		(29,218)
Impairment of assets	-		-		(13,534)
Other expenses	(8,446)		(5,503)		(22,305)
Other income, excluding interest income	3,324		3,528		27,152
Other financial gains	-		1,904		1,904
Unadjusted EBITDAX	(24,650)		117,420		134,901
Non-recurring
Impairment of assets	-		-		13,534
Non-recurring opex2	18,547		13,135		20,534
Insurance claim receipts3	-		-		(17,977)
Change in provision - Lemang PSC contingent   payments	-		-		7,333
Fair value loss on contingent considerations	534		-		1,920
Others4	2,442		375		1,684
	21,523		13,510		27,028
Adjusted EBITDAX	(3,127)		130,930		161,929

 

¹ Certain H1 2022 comparative information has been restated.  Please refer to Note 25 in the unaudited condensed consolidated interim financial statements.

² Non-recurring opex represents one-off operational costs and major maintenance/well intervention activities, in particular operating costs and FPSO rectification costs incurred at the PNLP Assets, Montara interim tanker storage, diesel fuel consumption by the FPSO during production shutdown and to power the reinjection compressor during production start-up.  The Group also incurred charges associated with short lifting a cargo and delivery delays and repair of a gas turbine generator at PM329 PSC.  The H1 2022 non-recurring costs mainly consisted of Montara Skua-11 well subsurface repairs and Stag structural marine maintenance and import hose replacement.  

³ Insurance claim receipts for the full year ended 2022 represented insurance claim received at Montara for the compensation for the loss of production relating to the Skua-11 well in 2020. 

⁴ Includes business development costs, transition team costs relating to the terminated Maari acquisition and internal reorganisation costs.

 

Net cash/debt

 

Net cash/debt is a non-IFRS measure which does not have a standardised definition prescribed by IFRS.  Management uses this measure to analyse the net borrowing position of the Group.

 

USD'000		30 June 2023		30 June 2022		31 December 2022
Cash and cash equivalents		118,782		161,628		123,329
Borrowings		(111,000)		-		-
Net cash/(debt)		7,782		161,628		123,329

 

Net cash/debt is defined as the sum of cash and cash equivalents and restricted cash, less the outstanding principal sum of borrowings.

 

On 17 February 2023, the Group closed the Interim Facility with two international banks prior to closing the RBL facility.  US$28.5 million of the Interim Facility was drawn in February 2023 to fund the acquisition of the Sinphuhorm Assets.  The second drawdown of US$21.5 million occurred in May 2023 to fund the US$20.5 million payment into the CWLH abandonment trust fund.  The loan was fully repaid on 1 June 2023.

 

On 22 May 2023, the Group announced the closing of a US$200.0 million RBL facility with the RBL Banks for the purpose of repaying the Interim Facility and to fund the Group's operations and capital investment programme, particularly the Akatara gas development project onshore Indonesia.  The facility incorporates standard terms and conditions, including a parent company financial covenant for a maximum total debt of 3.5 times annual EBITDAX, tested bi-annually on 30 June and 31 December.  The assets under the RBL facility are required to hold a total minimum liquidity balance of US$15.0 million and the Group needs to carry sufficient cash to cover forward-looking capital expenditures for two quarters.

 

Under the RBL facility, the Group had drawn US$111.0 million as at 30 June 2023.  Cash and cash equivalents as at 30 June 2023 were US$118.8 million, including the proceeds from the equity fundraise on 6 June 2023, which generated a net cash position of US$7.8 million at the end of the period.  

 

On 6 June 2023, the Company entered into a committed standby working capital facility with Tyrus for a facility size of up to US$35.0 million.  The standby working capital facility closed at US$31.9 million, after deducting US$3.1 million, representing the gross proceeds of the equity fundraise in excess of US$50.0 million.  The facility does not amortise and matures on 31 December 2024.  The working capital facility carries interest of 15% on drawn amounts and 5% on undrawn amounts and can be repaid or cancelled without penalties.  The standby working capital facility was undrawn as at 30 June 2023.

 

 

2023 PRINCIPAL FINANCIAL RISKS AND UNCERTAINTIES

 

The Group manages principal risks and uncertainties via its risk management framework.  The Group is exposed to a variety of political, technological, environmental, operational and financial risks which are monitored and/or mitigated to acceptable levels.

 

The Group's risk management framework provides a systematic process for the identification of the principal risks which have the possibility of impacting the Group's strategic objectives.  The Board regularly reviews the principal risks and defines corporate targets based on acceptable levels of risk.  The Board assesses material risks with a full review of the risk matrix at least twice per year.

 

Details of the principal risks and uncertainties faced by the Group as at 30 June 2023 remain unchanged from the risks disclosed in the 2022 Annual Report pages 25 to 27.  The Group's risk mitigation activities also remain unchanged.

 

GOING CONCERN

 

The Directors have adopted the going concern basis in preparing these unaudited condensed consolidated interim financial statements, having considered the principal financial risks and uncertainties of the Group.

 

The Directors believe that the Group is well placed to manage its financing and other business risks satisfactorily.  The Directors have a reasonable expectation that the Group will have adequate resources to continue in operation for at least 18 months from the date of these unaudited condensed consolidated interim financial statements.  They therefore consider it appropriate to adopt the going concern basis of accounting in preparing these financial statements.

 

 

 

STATEMENT OF DIRECTORS' RESPONSIBILITIES

 

The Directors confirm that to the best of their knowledge:

 

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

 

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

 

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

 

By order of the Board,

 

 

 

 

 

Bert-Jaap Dijkstra

Executive Director                                                                              

Chief Financial Officer                                                       

19 September 2023                                                                           

 

 

 

 

CAUTIONARY STATEMENT

 

This Interim Management Report (IMR) has been prepared solely to provide additional information to shareholders to assess the Group's strategies and the potential for those strategies to succeed.  The IMR should not be relied on by any other party or for any other purpose.

 

The IMR contains certain forward-looking statements.  These statements are made by the directors in good faith based on the information available to them up to the time of their approval of this report but such statements should be treated with caution due to the inherent uncertainties, including both economic and business risk factors, underlying any such forward-looking information.

 

Condensed Consolidated Statement of Profit or Loss and Other Comprehensive Income

for the six months ended 30 June 2023

 

		Six months ended 30 June 2023		Six months ended 30 June  2022		Twelve months ended 31 December 2022
		Unaudited		Unaudited		Audited
				Restated*
	Notes	USD'000		USD'000		USD'000
Consolidated statement of profit or loss
Revenue		86,660		225,639		421,602
Production costs	4	(90,650)		(92,983)		(250,700)
Depletion, depreciation and amortisation	4	(24,574)		(35,135)		(61,834)
Administrative staff costs		(15,538)		(15,165)		(29,218)
Other expenses	4	(8,446)		(5,503)		(22,305)
Impairment of assets		-		-		(13,534)
Other income		4,790		3,698		28,033
Finance costs	5	(22,517)		(4,784)		(11,408)
Other financial gains		-		1,904		1,904
(Loss)/Profit before tax		(70,275)		77,671		62,540
Income tax credit/(expense)	6	10,341		(34,126)		(54,018)
(Loss)/Profit for the period/year		(59,934)		43,545		8,522
(Loss)/Earnings per ordinary share
Basic and diluted (US$)	7	(0.13)		0.09		0.02
Other comprehensive loss
(Loss)/Profit for the period/year		(59,934)		43,545		8,522
Items that may be reclassified subsequently   to profit or loss:
Loss on unrealised cash flow hedges		(10,985)		-		-
Hedging gain reclassified to profit or loss		-		-		-
		(10,985)		-		-
Tax credit relating to components of other   comprehensive loss		2,160		-		-
Other comprehensive loss		(8,825)		-		-
Total comprehensive (loss)/income for the      period/year		(68,759)		43,545		8,522

 

 

 

 

 

 

 

 

*Certain H1 2022 comparative information has been restated.  Please refer to Note 25. 

 

 

Condensed Consolidated Statement of Financial Position as at 30 June 2023

 

		30 June 2023		30 June 2022		31 December 2022
		Unaudited		Unaudited		Audited
				Restated*
	Notes	USD'000		USD'000		USD'000
Assets
Non-current assets
Intangible exploration assets	8	78,730		77,027		77,928
Oil and gas properties	9	452,671		350,404		456,768
Plant and equipment	9	7,329		8,896		7,318
Right-of-use assets	9	37,980		9,288		8,193
Investment in associate	10	27,853		-		-
Other receivables and prepayment	11	191,127		46,817		90,590
Deferred tax assets		2,963		20,049		9,118
Cash and cash equivalents	12	1,000		621		676
Total non-current assets		799,653		513,102		650,591
Current assets
Inventories		47,085		38,162		18,911
Trade and other receivables	11	73,049		13,633		20,368
Tax recoverable		8,496		8,162		9,725
Cash and cash equivalents	12	117,782		161,007		122,653
Total current assets		246,412		220,964		171,657
Total assets		1,046,065		734,066		822,248
Equity and liabilities
Equity
Capital and reserves
Share capital	13	456		359		339
Share premium account	13	51,827		870		983
Merger reserve	14	146,270		146,270		146,270
Share based payments reserve		27,365		26,619		26,907
Capital redemption reserve	15	24		-		21
Hedging reserve	16	(8,825)		-		-
(Accumulated losses)/Retained earnings		(113,805)		2,281		(51,787)
Total equity		103,312		176,399		122,733
*Certain H1 2022 comparative information has been restated.  Please refer to Note 25.
		30 June 2023		30 June 2022		31 December 2022
		Unaudited		Unaudited		Audited
	Notes	USD'000		USD'000		USD'000
Non-current liabilities
Provisions	17	579,219		413,451		508,539
Borrowings	18	82,194		-		-
Lease liabilities		24,818		1,154		2,880
Other payable	19	29,014		-		-
Derivative financial instruments	20	6,386		-		-
Deferred tax liabilities		71,828		59,032		88,406
Total non-current liabilities		793,459		473,637		599,825
Current liabilities
Borrowings	18	22,802		-		-
Lease liabilities		14,107		9,576		6,227
Trade and other payables	19	73,752		46,575		73,752
Derivative financial instruments	20	4,599		-		-
Warrants liability	21	6,147		-		-
Provisions	18	16,941		3,503		703
Tax liabilities		10,946		24,376		19,008
Total current liabilities		149,294		84,030		99,690
Total liabilities		942,753		557,667		699,515
Total equity and liabilities		1,046,065		734,066		822,248