2023 Half Year Results
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
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USD'000 except where indicated |
H1 2023 |
H1 2022 |
FY 2022 |
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Production, boe/day1 |
12,339 |
15,008 |
11,487 |
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Realised oil price per barrel of oil equivalent (US$/boe)2 |
86.15 |
109.52 |
103.85 |
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Realised gas price per thousand standard cubic feet (US$/mscf) |
1.41 |
2.03 |
1.63 |
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Revenue |
86,660 |
225,639 |
421,602 |
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Production costs (restated3) |
(90,650) |
(92,983) |
(250,700) |
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Adjusted unit operating costs per barrel of oil equivalent (US$/boe)4 |
40.27 |
25.71 |
37.49 |
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Adjusted EBITDAX4 (restated3) |
(3,127) |
130,930 |
161,929 |
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(Loss)/Profit after tax (restated3) |
(59,934) |
43,545 |
8,522 |
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(Loss)/Earnings per ordinary share: basic and diluted (US$) (restated3) |
(0.13) |
0.09 |
0.02 |
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Operating cash flows before movement in working capital (restated3) |
(24,179) |
116,899 |
158,148 |
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Capital expenditure |
23,807 |
13,621 |
82,876 |
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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
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Jadestone Energy plc. |
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Paul Blakeley, President and CEO |
+65 6324 0359 (Singapore) |
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Bert-Jaap Dijkstra, CFO |
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Phil Corbett, Investor Relations Manager |
+44 7713 687 467 (UK) |
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Stifel Nicolaus Europe Limited (Nomad, Joint Broker) |
+44 (0) 20 7710 7600 (UK) |
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Callum Stewart / Jason Grossman / Ashton Clanfield |
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Jefferies International Limited (Joint Broker) |
+44 (0) 20 7029 8000 (UK) |
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Tony White / Will Soutar |
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Camarco (Public Relations Advisor) |
+44 (0) 203 757 4980 (UK) |
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Billy Clegg / Andrew Turner / Elfie Kent |
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.
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USD'000 except where indicated |
Six months ended 30 June 2023 |
Six months ended 30 June 2022 |
Twelve months ended 31 December 2022
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Sales volume, barrels of oil equivalent (boe) |
1,119,011 |
2,199,583 |
4,326,770 |
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Production, boe/day1 |
12,339 |
15,008 |
11,487 |
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Realised oil price per barrel of oil equivalent (US$/boe)2 |
86.15 |
109.52 |
103.85 |
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Realised gas price per thousand standard cubic feet (US$/mscf) |
1.41 |
2.03 |
1.63 |
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Revenue |
86,660 |
225,639 |
421,602 |
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Production costs (restated3) |
(90,650) |
(92,983) |
(250,700) |
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Adjusted unit operating costs per barrel of oil equivalent, (US$/boe)4 |
40.27 |
25.71 |
37.49 |
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Adjusted EBITDAX4 (restated3) |
(3,127) |
130,930 |
161,929 |
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Unit depletion, depreciation & amortisation (US$/boe) |
13.15 |
12.06 |
10.80 |
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Impairment of assets |
- |
- |
(13,534) |
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(Loss)/Profit before tax (restated3) |
(70,275) |
77,671 |
62,540 |
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(Loss)/Profit after tax (restated3) |
(59,934) |
43,545 |
8,522 |
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(Loss)/Earnings per ordinary share: basic and diluted (US$) (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 |
Condensed Consolidated Statement of Changes in Equity
for the six months ended 30 June 2023
|
|
|
|
|
|
|
|
Share |
|
|
|
|
|
|
|
|
|
|
|
|
Share |
|
|
|
based |
|
Capital |
|
|
|
|
|
|
|
|
Share |
|
premium |
|
Merger |
|
payments |
|
redemption |
|
Hedging |
|
Accumulated |
|
|
|
|
capital |
|
account |
|
reserve |
|
reserve |
|
reserve |
|
reserve |
|
losses |
|
Total |
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
USD''000 |
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 1 January 2022 |
358 |
|
201 |
|
146,270 |
|
25,936 |
|
- |
|
- |
|
(35,023) |
|
137,742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit for the period, representing total comprehensive income for the period |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
43,545 |
|
43,545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend paid |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(6,241) |
|
(6,241) |
|
Share-based payments |
- |
|
- |
|
- |
|
683 |
|
- |
|
- |
|
- |
|
683 |
|
Shares issued (Note 13) |
1 |
|
669 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
670 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total transactions with owners, recognised directly in equity |
1 |
|
669 |
|
- |
|
683 |
|
- |
|
- |
|
(6,241) |
|
(4,888) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 30 June 2022 (Restated)* |
359 |
|
870 |
|
146,270 |
|
26,619 |
|
- |
|
- |
|
2,281 |
|
176,399 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share |
|
|
|
|
|
|
|
|
|
|
|
|
Share |
|
|
|
based |
|
Capital |
|
|
|
|
|
|
|
|
Share |
|
premium |
|
Merger |
|
payments |
|
redemption |
|
Hedging |
|
Accumulated |
|
|
|
|
capital |
|
account |
|
reserve |
|
reserve |
|
reserve |
|
reserve |
|
losses |
|
Total |
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
USD''000 |
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 1 January 2022 |
358 |
|
201 |
|
146,270 |
|
25,936 |
|
- |
|
- |
|
(35,023) |
|
137,742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit for the year, representing total comprehensive income for the year |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
8,522 |
|
8,522 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends paid |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(9,216) |
|
(9,216) |
|
Share-based payments |
- |
|
- |
|
- |
|
971 |
|
- |
|
- |
|
- |
|
971 |
|
Shares issued (Note 13) |
2 |
|
782 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
784 |
|
Share repurchased (Note 13) |
(21) |
|
- |
|
- |
|
- |
|
21 |
|
- |
|
(16,070) |
|
(16,070) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total transactions with owners, recognised directly in equity |
(19) |
|
782 |
|
- |
|
971 |
|
21 |
|
- |
|
(25,286) |
|
(23,531) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 31 December 2022 |
339 |
|
983 |
|
146,270 |
|
26,907 |
|
21 |
|
- |
|
(51,787) |
|
122,733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share |
|
|
|
|
|
|
|
|
|
|
|
|
Share |
|
|
|
based |
|
Capital |
|
|
|
|
|
|
|
|
Share |
|
premium |
|
Merger |
|
payments |
|
redemption |
|
Hedging |
|
Accumulated |
|
|
|
|
capital |
|
account |
|
reserve |
|
reserve |
|
reserve |
|
reserve |
|
losses |
|
Total |
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
USD''000 |
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 1 January 2023 |
339 |
|
983 |
|
146,270 |
|
26,907 |
|
21 |
|
- |
|
(51,787) |
|
122,733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit for the period, representing total comprehensive income for the period |
- |
|
- |
|
- |
|
- |
|
- |
|
- |
|
(59,934) |
|
(59,934) |
|
Other comprehensive loss for the period |
- |
|
- |
|
- |
|
- |
|
- |
|
(8,825) |
|
- |
|
(8,825) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Share-based payments |
- |
|
- |
|
- |
|
458 |
|
- |
|
- |
|
- |
|
458 |
|
Shares issued (Note 13) |
120 |
|
50,844 |
|
- |
|
- |
|
- |
|
- |
|
- |
|
50,964 |
|
Shares repurchased (Note 13) |
(3) |
|
- |
|
- |
|
- |
|
3 |
|
- |
|
(2,084) |
|
(2,084) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total transactions with owners, recognised directly in equity |
117 |
|
50,468 |
|
- |
|
458 |
|
3 |
|
- |
|
(2,084) |
|
49,338 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 30 June 2023 |
456 |
|
51,827 |
|
146,270 |
|
27,365 |
|
24 |
|
(8,825) |
|
(113,805) |
|
103,312 |
Condensed Consolidated Statement of Cash Flows for the six months ended 30 June 2022
|
|
|
Six months |
|
Six months |
|
Twelve |
|
|
|
ended |
|
ended |
|
months ended |
|
|
|
30 June |
|
30 June |
|
31 December |
|
|
|
2023 |
|
2022 |
|
2022 |
|
|
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
|
|
|
Restated* |
|
|
|
|
Notes |
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
Operating activities |
|
|
|
|
|
|
|
(Loss)/Profit before tax |
|
(70,275) |
|
77,671 |
|
62,540 |
|
Adjustments for: |
|
|
|
|
|
|
|
Depletion, depreciation and amortisation |
4 / 9 |
24,574 |
|
35,135 |
|
61,834 |
|
Finance costs |
5 |
22,517 |
|
4,784 |
|
11,408 |
|
Share-based payments |
|
458 |
|
683 |
|
971 |
|
Allowance for slow moving inventories |
|
13 |
|
- |
|
3,768 |
|
Interest income |
|
(1,466) |
|
(2,074) |
|
(881) |
|
Provision for doubtful debts |
|
- |
|
446 |
|
- |
|
Unrealised foreign exchange loss |
|
- |
|
241 |
|
245 |
|
Assets written off |
|
- |
|
13 |
|
212 |
|
Impairment of oil and gas properties |
|
- |
|
- |
|
13,534 |
|
Change in provision |
|
- |
|
- |
|
7,333 |
|
Accretion income on Australian tax repayment plan |
|
- |
|
- |
|
(1,904) |
|
Reversal of impairment of amount due from joint arrangement partner |
|
- |
|
- |
|
(912) |
|
|
|
|
|
|
|
|
|
Operating cash flows before movements in working capital |
|
(24,179) |
|
116,899 |
|
158,148 |
|
|
|
|
|
|
|
|
|
(Increase)/Decrease in trade and other receivables |
|
(36,158) |
|
20,256 |
|
41,183 |
|
Increase in inventories |
|
(18,630) |
|
(10,774) |
|
(1,096) |
|
Increase/(Decrease) in trade and other payables |
|
24,411 |
|
(22,389) |
|
(2,471) |
|
|
|
|
|
|
|
|
|
Cash (used in)/generated from operations |
|
(54,556) |
|
103,992 |
|
195,764 |
|
|
|
|
|
|
|
|
|
Net tax paid |
|
(4,755) |
|
(34,177) |
|
(33,130) |
|
|
|
|
|
|
|
|
|
Net cash (used in)/generated from operating activities |
|
(59,311) |
|
69,646 |
|
162,634 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*Certain H1 2022 comparative information has been restated. Please refer to Note 25. |
||||||
|
|
|
|
|
|
|
|
|
|
|
Six months |
|
Six months |
|
Twelve |
|
|
|
ended |
|
ended |
|
months ended |
|
|
|
30 June |
|
30 June |
|
31 December |
|
|
|
2023 |
|
2022 |
|
2022 |
|
|
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
Notes |
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
Investing activities |
|
|
|
|
|
|
|
Cash paid for acquisition of Sinphuhorm Assets |
10 |
(27,853) |
|
- |
|
- |
|
Cash received from acquisition of CWLH Assets |
|
- |
|
- |
|
5,750 |
|
Cash paid for acquisition of 10% interest of Lemang PSC |
|
- |
|
- |
|
(500) |
|
Payment for oil and gas properties |
9 |
(22,703) |
|
(10,687) |
|
(78,938) |
|
Payment for plant and equipment |
9 |
(302) |
|
(253) |
|
(356) |
|
Payment for intangible exploration assets |
8 |
(434) |
|
(2,424) |
|
(3,334) |
|
Placement of decommissioning trust fund for CWLH Assets |
|
(41,000) |
|
- |
|
(41,000) |
|
Placement of abandonment cess fund for PenMal Assets |
|
- |
|
(169) |
|
(397) |
|
Interest received |
|
1,466 |
|
170 |
|
881 |
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
(90,826) |
|
(13,363) |
|
(117,894) |
|
|
|
|
|
|
|
|
|
Financing activities |
|
|
|
|
|
|
|
Net proceeds from issuance of shares |
|
51,070 |
|
670 |
|
784 |
|
Shares repurchased |
|
(2,084) |
|
- |
|
(16,070) |
|
Dividends paid |
|
- |
|
(6,241) |
|
(9,216) |
|
Total drawdown from borrowings |
|
161,000 |
|
- |
|
- |
|
Repayment of borrowings |
|
(50,000) |
|
- |
|
- |
|
Repayment of lease liabilities |
|
(7,009) |
|
(6,518) |
|
(13,914) |
|
Interest on lease liabilities paid |
|
(1,027) |
|
(400) |
|
(769) |
|
Interest on borrowings paid |
|
(793) |
|
- |
|
- |
|
Payment for borrowings costs |
|
(5,535) |
|
- |
|
- |
|
Interest paid |
|
(32) |
|
(200) |
|
(91) |
|
|
|
|
|
|
|
|
|
Net cash generated from/(used in) financing activities |
|
145,590 |
|
(12,689) |
|
(39,276) |
|
|
|
|
|
|
|
|
|
Net (decrease)/increase in cash and cash equivalents |
|
(4,547) |
|
43,763 |
|
5,464 |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at beginning of the period/year |
|
123,329 |
|
117,865 |
|
117,865 |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of the period/year |
|
118,782 |
|
161,628 |
|
123,329 |
Explanation Notes to the Condensed Consolidated Interim Financial Statements
for the six months ended 30 June 2023
1. GENERAL INFORMATION
Jadestone Energy plc (the "Company" or "Jadestone") is an oil and gas company incorporated and registered in England and Wales. The Company's registration number is 13152520. The Company is the ultimate parent company of all Jadestone subsidiaries (the "Group").
The Company's shares are traded on AIM under the symbol "JSE".
The financial statements are expressed in United States Dollars ("US$" or "USD").
The Group is engaged in production, development, exploration and appraisal activities in Australia, Malaysia, Vietnam, Indonesia and Thailand. The Group's producing assets are in the Vulcan (Montara) basin, Carnarvon (Stag) basin and Cossack, Wanaea, Lambert, and Hermes oil fields, located in offshore of Western Australia, the East Piatu, East Belumut, West Belumut and Chermingat fields, located in shallow water in offshore Peninsular Malaysia, and in the Sinphuhorm gas field onshore north-east Thailand.
The Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower, Singapore 079909. The registered office of the Company is 6th Floor, 60 Gracechurch Street, London, EC3V 0HR United Kingdom.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PREPARATION
The annual financial statements of the Jadestone Energy plc will be prepared in accordance with United Kingdom adopted International Accounting Standards. The condensed set of consolidated financial statements included in this half‑yearly financial report has been prepared in accordance with United Kingdom adopted International Accounting Standard 34 'Interim Financial Reporting'.
These unaudited condensed consolidated interim financial statements do not comprise statutory accounts within the meaning of section 435 of the Companies Act 2006 ("the Act"). They do not contain all disclosures required by IFRS for annual financial statements and should be read in conjunction with the Group's audited consolidated financial statements for the year ended 31 December 2022. The information for the year ended 31 December 2022 does not constitute statutory accounts as defined in section 434 of the Companies Act 2006. A copy of the statutory accounts for that year has been delivered to the Registrar of Companies. The auditors reported on those accounts: their report was unqualified, did not draw attention to any matters by way of emphasis and did not contain a statement under section 498(2) or (3) of the Companies Act 2006.
These financial statements have been prepared on an historical cost basis, except for financial instruments classified as financial instruments at fair value, which are stated at their fair values, and operating leases which are stated at the present value of future cash payments.
In addition, these financial statements have been prepared using the accrual basis of accounting.
GOING CONCERN
The Directors have considered the going concern assessment period of up to 31 December 2024 (the "going concern period"). The Group regularly monitors its cash, funding and liquidity position. Near-term cash projections are revised and underlying assumptions reviewed, generally monthly, and longer-term projections are also updated regularly.
The Group's cash forecast and scenario analysis is, among other factors, based on commodity prices per the current forward curve taking into account downside risks the associated impacts. In addition, under the RBL the Group has also undertaken commodity hedging. Sensitivities were created and included, among others, a reasonably possible low case and high case oil price; and various hedging scenarios for duration and volumes.
Various risking scenarios, such as medium to long-term oil prices which could also be potentially impacted by the transition to a lower carbon economy, costs estimates (including inflation assumptions) for, and phasing of, operating and capital expenditure have been considered. In addition, the Group is also potentially exposed to potential production interruptions such as weather downtime and planned and unplanned shutdowns for workovers and repair and maintenance activities.
The Directors have assessed that based on the near-term cash projections for the going concern period, the Group will have sufficient cash resources in place throughout the going concern period, also after taking into consideration of the various risking scenarios.
Having taken into consideration the above factors, the Directors have reasonable expectation that the Group will continue in operational existence for the going concern period. Accordingly, they adopted the going concern basis in preparing these unaudited condensed consolidated interim financial statements.
Adoption of new and revised standards
New and amended IFRS standards that are effective for the current period
The Group has applied the following amendments that is relevant to the Group for the first time with effect from 1 January 2023.
- Amendments to IAS 1 Classification of Liabilities as Current or Non-current - Deferral of Effective
Date
- Amendments to IAS 1 Making Materiality Judgements - Disclosure of Accounting Policies
And Practice
Statement 2
- Amendments to IAS 8 Definition of Accounting Estimates
- Amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single
Transaction
The amendments are effective for annual periods beginning on 1 January 2023 and require prospective application. The adoption of these amendments has not resulted in changes to the Group's accounting policies.
3. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY
Critical accounting judgments and key sources of estimation uncertainty
In the application of the Group's accounting policies, management is required to make judgments, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised, if the revision affects only that period, or in the period of the revision and future periods, if the revision affects both current and future periods.
The key judgements and sources of estimation uncertainty remain the same as disclosed in Jadestone's audited consolidated financial statements for the year ended 31 December 2022.
4. OPERATING COSTS
|
|
|
Six months ended |
|
Six months ended |
|
Twelve months ended |
|
|
|
30 June |
|
30 June |
|
31 December |
|
|
|
2023 |
|
2022 |
|
2022 |
|
|
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
|
|
|
Restated* |
|
|
|
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
Production costs |
|
87,615 |
|
90,115 |
|
242,359 |
|
Tariffs and transportation costs |
|
3,035 |
|
2,868 |
|
8,341 |
|
|
|
|
|
|
|
|
|
Total production costs |
|
90,650 |
|
92,983 |
|
250,700 |
|
|
|
|
|
|
|
|
|
Depletion and amortisation of oil and gas properties |
|
17,243 |
|
28,681 |
|
48,203 |
|
Depreciation of plant equipment and right-of-use assets |
|
7,331 |
|
6,454 |
|
13,631 |
|
|
|
|
|
|
|
|
|
Total depletion, depreciation and amortisation |
|
24,574 |
|
35,135 |
|
61,834 |
|
|
|
|
|
|
|
|
|
Corporate costs |
|
8,433 |
|
5,057 |
|
18,325 |
|
Other operating expenses |
|
13 |
|
446 |
|
3,980 |
|
|
|
|
|
|
|
|
|
Total other expenses |
|
8,446 |
|
5,503 |
|
22,305 |
5. FINANCE COSTS
|
|
|
Six months ended |
|
Six months ended |
|
Twelve months ended |
|
|
|
30 June |
|
30 June |
|
31 December |
|
|
|
2023 |
|
2022 |
|
2022 |
|
|
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
Interest expense and others |
|
6,553 |
|
600 |
|
2,780 |
|
Accretion expense |
|
9,817 |
|
4,184 |
|
8,628 |
|
Warrants expense |
|
6,147 |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
22,517 |
|
4,784 |
|
11,408 |
*Certain H1 2022 comparative information has been restated. Please refer to Note 25.
6. INCOME TAX EXPENSE
|
|
|
Six months ended 30 June 2023 Unaudited
USD'000 |
|
Six months ended 30 June 2022 Unaudited Restated* USD'000 |
|
Twelve months ended 31 December 2022 Audited
USD'000 |
|
|
|
|
|
|
|
|
|
Current tax |
|
|
|
|
|
|
|
Corporate tax charge |
|
|
|
29,154 |
|
15,656 |
|
Overprovision in prior year |
|
(2,176) |
|
- |
|
666 |
|
|
|
|
|
|
|
|
|
|
|
(2,176) |
|
29,154 |
|
16,322 |
|
Australian petroleum resource rent tax ("PRRT") |
|
- |
|
(162) |
|
(1,121) |
|
Malaysian petroleum income tax ("PITA") |
|
98 |
|
5,928 |
|
11,899 |
|
|
|
|
|
|
|
|
|
|
|
(2,078) |
|
34,920 |
|
27,100 |
|
|
|
|
|
|
|
|
|
Deferred tax |
|
|
|
|
|
|
|
Corporate tax |
|
(8,833) |
|
(4,042) |
|
14,149 |
|
PRRT |
|
(231) |
|
3,244 |
|
7,032 |
|
PITA |
|
801 |
|
4 |
|
5,737 |
|
|
|
|
|
|
|
|
|
|
|
(8,263) |
|
(794) |
|
26,918 |
|
|
|
|
|
|
|
|
|
|
|
(10,341) |
|
34,126 |
|
54,018 |
*Certain H1 2022 comparative information has been restated. Please refer to Note 25.
7. (LOSS)/EARNINGS PER ORDINARY SHARE
The calculation of the basic and diluted (loss)/earnings per share is based on the following data:
|
|
|
Six months ended |
|
Six months ended |
|
Twelve months ended |
|
|
|
30 June |
|
30 June |
|
31 December |
|
|
|
2023 |
|
2022 |
|
2022 |
|
|
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
|
|
|
Restated* |
|
|
|
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
(Loss)/Profit for the purposes of basic and diluted per share, being the net profit for the period attributable to equity holders of the Company |
|
(59,934) |
|
43,545 |
|
8,522 |
|
|
|
Number |
|
Number |
|
Number |
|
|
|
|
|
|
|
|
|
Weighted average number of ordinary shares for the purposes of basic EPS |
|
457,510,000 |
|
465,485,869 |
|
461,959,228 |
|
Effect of dilutive potential ordinary shares - share options |
|
- |
|
6,029,827 |
|
3,876,548 |
|
Effect of dilutive potential ordinary shares - performance shares |
|
- |
|
595,998 |
|
334,163 |
|
Effect of dilutive potential ordinary shares - restricted shares |
|
- |
|
178,887 |
|
202,823 |
|
|
|
|
|
|
|
|
|
Weighted average number of ordinary shares for the purposes of diluted EPS |
|
457,510,000 |
|
472,290,581 |
|
466,372,762 |
During the current period, 6,427,966 of weighted average potentially dilutive ordinary shares available for exercise from in the money vested options, associated with share options were excluded from the calculation of diluted EPS, as they are anti-dilutive in view of the loss for the period.
During the current period, 326,477 of weighted average contingently issuable shares associated under the Company's performance share plan based on the respective performance measures up to year-end were excluded from the calculation of diluted EPS, as they are anti-dilutive in view of the loss for the period.
During the current period, 445,288 of weighted average contingently issuable shares under the Company's restricted share plan were excluded from the calculation of diluted EPS, as they are anti-dilutive in view of the loss for the period.
During the current period, 3,977,901 of weighted average contingently issuable shares under the Company's warrants instrument were excluded from the calculation of diluted EPS, as they are anti-dilutive in view of the loss for the period.
|
|
|
Six months ended |
|
Six months ended |
|
Twelve months ended |
|
|
|
30 June |
|
30 June |
|
31 December |
|
|
|
2023 |
|
2022 |
|
2022 |
|
(Loss)/Earnings per share (US$) |
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
|
|
|
|
|
|
|
- - Basic and diluted |
|
(0.13) |
|
0.09 |
|
0.02 |
*Certain H1 2022 comparative information has been restated. Please refer to Note 25.
8. INTANGIBLE EXPLORATION ASSETS
|
|
Total USD'000 |
|
|
|
|
Cost |
|
|
As at 1 January 2022 |
93,241 |
|
Additions |
2,681 |
|
Transfer |
(18,895)* |
|
|
|
|
As at 30 June 2022 |
77,027 |
|
Additions |
901 |
|
|
|
|
As at 31 December 2022 |
77,928 |
|
Additions |
802 |
|
|
|
|
As at 30 June 2023 |
78,730 |
|
|
|
|
Impairment |
|
|
As at 1 January 2022/30 June 2022/31 December 2022/30 June 2023 |
- |
|
|
|
|
Net book value |
|
|
As at 30 June 2022 (unaudited) |
77,027 |
|
|
|
|
As at 31 December 2022 (audited) |
77,928 |
|
|
|
|
As at 30 June 2023 (unaudited) |
78,730 |
* The transfer in 2022 related to the Lemang PSC in Indonesia, following the final investment decision and award of the engineering, procurement, construction and installation contract which established commercial viability. The capitalised cost of US$18.9 million was transferred to development assets as disclosed in Note 9.
9. PROPERTY, PLANT AND EQUIPMENT
|
|
|
Oil and gas properties |
|
Plant and equipment |
|
Right-of-use assets |
|
Total |
||
|
|
|
Production assets |
|
Development assets |
|
|
|
|||
|
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost |
|
|
|
|
|
|
|
|
|
|
|
As at 1 January 2022 |
|
595,494 |
|
- |
|
12,334 |
|
48,368 |
|
656,196 |
|
Additions |
|
10,687 |
|
- |
|
253 |
|
1,583 |
|
12,523 |
|
Reclassification |
|
- |
|
18,895 |
|
- |
|
- |
|
18,895 |
|
Written off |
|
(3,704) |
|
- |
|
(67) |
|
(5,981) |
|
(9,752) |
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 30 June 2022 |
|
602,477 |
|
18,895 |
|
12,520 |
|
43,970 |
|
677,862 |
|
Changes in asset restoration obligations |
|
20,768 |
|
7 |
|
- |
|
- |
|
20,775 |
|
Acquisition of CWLH Assets |
|
41,976 |
|
- |
|
- |
|
- |
|
41,976 |
|
Acquisition of 10% interest in Lemang PSC |
|
- |
|
1,414 |
|
- |
|
- |
|
1,414 |
|
Additions |
|
51,632 |
|
16,619 |
|
103 |
|
5,773 |
|
74,127 |
|
Written off |
|
- |
|
- |
|
(260) |
|
- |
|
(260) |
|
Transfer |
|
- |
|
- |
|
(1,173) |
|
- |
|
(1,173) |
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 31 December 2022 |
|
716,853 |
|
36,935 |
|
11,190 |
|
49,743 |
|
814,721 |
|
Additions |
|
1,677 |
|
21,026 |
|
302 |
|
36,827 |
|
59,832 |
|
Transfer of 50% interest in PNLP Assets |
|
48,604* |
|
- |
|
- |
|
- |
|
48,604 |
|
Written off |
|
- |
|
- |
|
- |
|
(1,584) |
|
(1,584) |
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 30 June 2023 |
|
767,134 |
|
57,961 |
|
11,492 |
|
84,986 |
|
921,573 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated depletion, depreciation, amortisation and impairment |
|
|
|
|
|
|
|
|
|
|
|
As at 1 January 2022 |
|
241,902 |
|
- |
|
3,371 |
|
34,516 |
|
279,789 |
|
Charge for the period |
|
32,770 |
|
- |
|
307 |
|
6,147 |
|
39,224 |
|
Written off |
|
(3,704) |
|
- |
|
(54) |
|
(5,981) |
|
(9,739) |
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 30 June 2022 |
|
270,968 |
|
- |
|
3,624 |
|
34,682 |
|
309,274 |
|
Charge for the period |
|
12,518 |
|
- |
|
309 |
|
6,868 |
|
19,695 |
|
Impairment |
|
13,534 |
|
- |
|
- |
|
- |
|
13,534 |
|
Written off |
|
- |
|
- |
|
(61) |
|
- |
|
(61) |
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 31 December 2022 |
|
297,020 |
|
- |
|
3,872 |
|
41,550 |
|
342,442 |
|
Charge for the period |
|
26,800 |
|
- |
|
291 |
|
7,040 |
|
34,131 |
|
Impairment |
|
48,604* |
|
- |
|
- |
|
- |
|
48,604 |
|
Written off |
|
- |
|
- |
|
- |
|
(1,584) |
|
(1,584) |
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 30 June 2023 |
|
372,424 |
|
- |
|
4,163 |
|
47,006 |
|
423,593 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net book value |
|
|
|
|
|
|
|
|
|
|
|
As at 30 June 2022 (unaudited) |
|
331,509 |
|
18,895 |
|
8,896 |
|
9,288 |
|
368,588 |
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 31 December 2022 (audited) |
|
419,833 |
|
36,935 |
|
7,318 |
|
8,193 |
|
472,279 |
|
|
|
|
|
|
|
|
|
|
|
|
|
As at 30 June 2023 (unaudited) |
|
394,710 |
|
57,961 |
|
7,329 |
|
37,980 |
|
497,980 |
* On 14 April 2023, Jadestone assumed operatorship of the PNLP Assets following the decision of the previous operator to withdraw. Accordingly, the Group has assumed the previous operator's share of decommissioning liabilities following the transfer of operatorship, with a corresponding increase to the oil and gas properties balance. The oil and gas properties were impaired as at 30 June 2023 and offset against the non-current other payable (Note 20), due to the uncertainty in respect to a potential restart date for production under 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 subsequently may seek Jadestone Board's approval prior to sanctioning the project.
10. INVESTMENT IN ASSOCIATE
|
|
|
30 June 2023 Unaudited USD'000 |
|
30 June 2022 Unaudited USD'000 |
|
31 December 2022 Audited USD'000 |
|
|
|
|
|
|
|
|
|
At beginning of period/year |
|
- |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
Acquisition of 9.52% non-operated interest in Sinphuhorm Assets |
|
27,853 |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
At end of period/year |
|
27,853 |
|
- |
|
- |
On 19 January 2023, the Group executed a sale and purchase agreement with Salamander Energy (S.E. Asia) Limited, an affiliate of PT Medco Energi Internasional Tbk, to acquire its 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 the Dong Mun gas discovery onshore northeast Thailand. The acquisition was completed on 23 February 2023, for a cash consideration of US$27.9 million post customary closing adjustments. The effective date of the transaction was 1 January 2022.
11. TRADE AND OTHER RECEIVABLES
|
|
|
30 June 2023 |
|
30 June 2022 |
|
31 December 2022 |
|
|
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
|
|
|
Restated* |
|
|
|
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
Trade receivables |
|
6,388 |
|
535 |
|
6,332 |
|
Prepayments |
|
7,064 |
|
7,166 |
|
3,119 |
|
Other receivables and deposits |
|
51,678 |
|
2,175 |
|
4,859 |
|
Amount due from joint arrangement partners (net) |
|
2,589 |
|
226 |
|
4,268 |
|
Underlift crude oil inventories |
|
4,251 |
|
1,847 |
|
107 |
|
PRRT receivables |
|
- |
|
162 |
|
- |
|
VAT receivables |
|
1,079 |
|
1,522 |
|
1,683 |
|
|
|
|
|
|
|
|
|
|
|
73,049 |
|
13,633 |
|
20,368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30 June 2023 |
|
30 June 2022 |
|
31 December 2022 |
|
|
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
|
|
|
Restated* |
|
|
|
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
Non-current |
|
|
|
|
|
|
|
Other receivables |
|
181,798 |
|
41,895 |
|
83,192 |
|
VAT receivables |
|
9,329 |
|
4,922 |
|
7,398 |
|
|
|
|
|
|
|
|
|
|
|
191,127 |
|
46,817 |
|
90,590 |
|
|
|
|
|
|
|
|
|
|
|
264,176 |
|
60,450 |
|
110,958 |
The current other receivables as at 30 June 2023 mainly relates to a joint arrangement partner's share of future decommissioning costs when it exited two PSCs' licences during H1 2023.
The increase of non-current other receivables during the period represents additional payments of US$41.0 million into the CWLH abandonment trust fund. Additionally, the total accumulated cess payment paid to the Malaysian regulator of US$56.4 million for the PNLP Assets is now presented on a gross basis, as opposed to offsetting against the provision for asset retirement obligations, following the transfer of operatorship of the PSCs in April 2023. In 2022, this asset retirement obligation was presented on a net basis to reflect the PSCs were non-operated, in line with the Group's accounting policies. The asset retirement liability associated with the PSCs is now presented on a 100% gross position in the Group's balance sheet (Note 17).
12. CASH AND BANK BALANCES
|
|
|
30 June 2023 |
|
30 June 2022 |
|
31 December 2022 |
|
|
|
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
|
|
|
|
Reclassified* |
|
|
|
|
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
|
|
Cash and bank balances, representing cash and cash equivalents in the consolidated statement of cash flows, presented as: |
|
|
|
|
|
|
|
|
Non-current |
|
1,000 |
|
621 |
|
676 |
|
|
Current |
|
117,782 |
|
161,007 |
|
122,653 |
|
|
|
|
|
|
|
|
|
|
|
|
|
118,782 |
|
161,628 |
|
123,329 |
|
The non-current cash and cash equivalents represents the restricted cash balance of US$0.7 million (H1 2022: US$0.3 million) and US$0.3 million (H1 2022: US$0.3 million) in relation to a deposit placed for bank guarantee with respect to the PenMal Assets and Australian office building, respectively. The bank guarantees are expected to be in place for a period of more than twelve months. Accordingly, reclassification was made to H1 2022 comparatives to classify the amount as a non-current asset as disclosed in Note 25, as a result of the April 2022 IFRIC Agenda item "Demand Deposits with Restrictions on Use arising from a Contract with a Third Party (IAS 7 Statement of Cash Flows).
*Certain H1 2022 comparative information has been restated and reclassified between line items. Please refer to Note 25.
As part of the RBL facility, the Group must retain an aggregate amount of principal, interest, fees and costs payable for the next two quarters in the debt service reserve account ("DSRA"). An amount of US$8.2 million was deposited into the DSRA during H1 2023 and it is classified as a current asset.
13. SHARE CAPITAL AND SHARE PREMIUM ACCOUNT
|
|
|
Share capital |
|
Share premium account |
||
|
|
|
No. of shares |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
|
Issued and fully paid |
|
|
|
|
|
|
|
As at 1 January 2022 |
|
465,081,238 |
|
358 |
|
201 |
|
Issued during the period |
|
972,378 |
|
1 |
|
669 |
|
|
|
|
|
|
|
|
|
As at 30 June 2022 (Restated)* |
|
466,053,616 |
|
359 |
|
870 |
|
Issued during the period |
|
473,730 |
|
1 |
|
113 |
|
Share repurchases |
|
(18,173,683) |
|
(21) |
|
- |
|
|
|
|
|
|
|
|
|
As at 31 December 2022 |
|
448,353,663 |
|
339 |
|
983 |
|
Issued during the period |
|
94,283,543 |
|
120 |
|
50,844 |
|
Vesting of 2020 performance shares |
|
79,327 |
|
- |
|
- |
|
Vesting of 2020 restricted shares |
|
101,063 |
|
- |
|
- |
|
Share repurchased |
|
(2,051,022) |
|
(3) |
|
- |
|
|
|
|
|
|
|
|
|
As at 30 June 2023 |
|
540,766,574 |
|
456 |
|
51,827 |
On 19 January 2023, the Company suspended its share buyback programme. For the period ended 30 June 2023, the Company had acquired 2.1 million shares at a weighted average cost of £0.75 per share, resulting in total expenditure of US$1.8 million. The total nominal value of the shares repurchased was US$2,485. All shares repurchased were cancelled.
On 6 June 2023, the Company completed an equity fundraising, creating an additional 94,081,826 ordinary shares at £0.45 per share, which comprised of a placing and subscription of 92,312,691 new ordinary shares to existing and new institutional shareholders and a placing and subscription of 1,769,135 new ordinary shares to the Directors of the Company. Total gross proceeds were US$53.1 million, with net proceeds of US$51.1 million.
On 9 June 2023, the Company launched an open offer of up to 14,887,039 new ordinary shares, at £0.45 per share, to raise additional proceeds of up to EUR8.0 million (up to US$8.6 million). The open offer closed on 28 June 2023, raising a total of US$42,009 by issuing 73,557 new shares.
The Company has one class of ordinary share. Fully paid ordinary shares with par value of £0.001 per share carry one vote per share without restriction, and carry a right to dividends as and when declared by the Company.
*Certain H1 2022 comparative information has been restated. Please refer to Note 25.
14. MERGER RESERVE
The merger reserve arose from the difference between the carrying value and the nominal value of the shares of the Company, following completion of the internal reorganisation in 2021.
15. CAPITAL REDEMPTION RESERVE
The capital redemption reserve arose from the share buyback programme launched by the Company in August 2022. It represents the par value of the shares purchased and cancelled by the Company under the share buyback programme.
16. HEDGING RESERVE
|
|
30 June 2023 Unaudited USD'000 |
|
30 June 2022 Unaudited USD'000 |
|
31 December 2022 Audited USD'000 |
|
|
|
|
|
|
|
|
At beginning of the period/year |
- |
|
- |
|
- |
|
Loss arising on changes in fair value of hedging instruments during the period/year |
10,985 |
|
- |
|
- |
|
Income tax related to loss recognised in other comprehensive income |
(2,160) |
|
- |
|
- |
|
Net loss reclassified to profit or loss |
- |
|
- |
|
- |
|
Income tax related to amounts reclassified to profit or loss |
- |
|
- |
|
- |
|
|
|
|
|
|
|
|
At end of the period/year |
8,825 |
|
- |
|
- |
The hedging reserve represents the cumulative amount of gains and losses on hedging instruments deemed effective in cash flow hedges. The cumulative deferred gain or loss on the hedging instrument is recognised in profit or loss only when the hedged transaction impacts the profit or loss.
17. PROVISIONS
|
|
30 June 2023 |
|
30 June 2022 |
|
31 December 2022 |
|
|
Unaudited |
|
Unaudited |
|
Audited |
|
|
USD'000 |
|
USD'000 |
|
USD'000 |
|
|
|
|
|
|
|
|
Non-current |
|
|
|
|
|
|
Asset restoration obligations |
570,755 |
|
408,585 |
|
493,985 |
|
Others |
8,464 |
|
4,866 |
|
14,554 |
|
|
|
|
|
|
|
|
|
579,219 |
|
413,451 |
|
508,539 |
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
Asset restoration obligations |
9,551 |
|
- |
|
- |
|
Others |
7,390 |
|
3,503 |
|
703 |
|
|
|
|
|
|
|
|
|
16,941 |
|
3,503 |
|
703 |
|
|
|
|
|
|
|
|
|
574,656 |
|
416,954 |
|
509,242 |
The increase in the provision for asset restoration obligations by US$86.3 million during the period represents the additional decommissioning obligations of US$48.6 million following the transfer of operatorship of the PNLP Assets in April 2023. Additionally, US$28.2 million of asset retirement obligation associated with the PNLP Assets, net to Jadestone's 50% interest prior to transfer of operatorship, is now presented on a gross basis, with the Group is now being the operator of the PSCs. The cess payment paid to cover for this amount is now presented as a non-current other receivable in Note 11, in line with the Group's accounting policies. The Group also incurred accretion expense of US$9.6 million during the period.
18. BORROWINGS
|
|
|
30 June 2023 Unaudited USD'000 |
|
30 June 2022 Unaudited USD'000 |
|
31 December 2022 Audited USD'000 |
|
|
|
|
|
|
|
|
|
Non-current secured borrowings |
|
|
|
|
|
|
|
Reserve based lending facility |
|
82,194 |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
Current secured borrowings |
|
|
|
|
|
|
|
Reserve based lending facility |
|
22,802 |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
104,996 |
|
- |
|
- |
On 17 February 2023, the Group closed a US$50.0 million Interim Facility with two international banks to provide additional liquidity 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 primarily to fund the US$20.5 million payment into the CWLH abandonment trust fund. The Interim Facility was repaid on 1 June 2023 from the RBL facility obtained by the Group in May 2023. The Group had incurred interest expense of US$1.3 million from the Interim Facility, which was recorded as finance costs in Note 5.
On 19 May 2023, the Group signed a US$200.0 million RBL facility with a group of four international banks ("the RBL Banks"). The facility tenor is four years, with the final maturity date being the earlier of 31 March 2027 and the projected reserves tail1 (which is expected later). The borrowing base is secured over the Group's main producing assets being Montara, Stag, CWLH, Sinphuhorm Assets, the PenMal Assets' PM323 and PM329 PSCs and the Group's development asset being the Lemang PSC. The borrowing base as at 30 June 2023 was US$200.0 million.
The RBL facility pays interest at 450 basis points over the secured overnight financing rate, plus the applicable credit spread. The Group also pays customary arrangement and commitment fees.
The first drawdown of the RBL facility of US$111.0 million occurred on 1 June 2023. The loan incurred costs of US$6.9 million and the fair value of the loan at drawdown had an amortised carrying value of US$104.1 million. For the period ended 30 June 2023, the Group had incurred interest expense of US$0.9 million and US$0.3 million of commitment fees, which were recorded as finance costs in Note 5.
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 was finalised at US$31.9 million, after deduction of US$3.1 million of excess funds from the total gross funds of US$53.1 million raised from the equity placing and open offer. The facility will mature with a bullet repayment on 31 December 2024. The facility bears 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.
1 Reserves tail date refers to the last day of the quarter immediately preceding the quarter in which the remaining borrowing base reserves are forecast to be 25 per cent (or less) of the initial approved borrowing base reserves.
19. TRADE AND OTHER PAYABLES
|
|
|
30 June 2023 Unaudited USD'000 |
|
30 June 2022 Unaudited USD'000 |
|
31 December 2022 Audited USD'000 |
|
|
|
|
|
|
|
|
|
Current |
|
|
|
|
|
|
|
Trade payables |
|
24,539 |
|
5,602 |
|
13,606 |
|
Other payables |
|
15,506 |
|
4,862 |
|
8,643 |
|
Accruals |
|
32,215 |
|
33,267 |
|
36,757 |
|
Contingent payments |
|
- |
|
- |
|
5,000 |
|
Malaysian supplementary payment payables |
|
732 |
|
2,839 |
|
855 |
|
Amount due to joint arrangement partner |
|
433 |
|
- |
|
1,269 |
|
Overlift crude oil inventories |
|
- |
|
- |
|
7,357 |
|
GST/VAT payables |
|
327 |
|
5 |
|
265 |
|
|
|
|
|
|
|
|
|
|
|
73,752 |
|
46,575 |
|
73,752 |
|
|
|
|
|
|
|
|
|
Non-current |
|
|
|
|
|
|
|
Other payable |
|
29,014 |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
102,766 |
|
46,575 |
|
73,752 |
Non-current other payable represents future activities which are operational in nature for which cash advances are to be received from a joint arrangement partner for its share of future decommissioning costs when it exited two PSCs' licences during H1 2023.
20. DERIVATIVE FINANCIAL INSTRUMENTS
The Group uses derivatives to manage its exposure to oil price fluctuations. Oil hedges are undertaken using swaps. All contracts are referenced to Dated Brent oil prices. During the period, the Group entered into commodity swaps that are designated as a cash flow hedge.
|
|
|
30 June 2023 Unaudited USD'000 |
|
30 June 2022 Unaudited USD'000 |
|
31 December 2022 Audited USD'000 |
|
|
|
|
|
|
|
|
|
Derivative financial liabilities |
|
|
|
|
|
|
|
Designated as cash flow hedges |
|
|
|
|
|
|
|
Commodity capped swap |
|
10,985 |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
Analysed as: |
|
|
|
|
|
|
|
Current |
|
4,599 |
|
- |
|
- |
|
Non-current |
|
6,386 |
|
- |
|
- |
|
|
|
|
|
|
|
|
|
|
|
10,985 |
|
- |
|
- |
The following is a summary of the Group's outstanding derivative contracts:
|
Contract quantity |
Type of contracts |
Terms |
Contract price |
Hedge classification |
Fair value asset at 30 June 2023 Unaudited USD'000 |
Fair value asset at 30 June 2022 Unaudited USD'000 |
Fair value asset at 31 December 2022 Audited USD'000 |
|
|
|
|
|
|
|
|
|
|
Contracts designated as cash flow hedges |
|
|
|
|
|||
|
|
|
|
|
|
|
|
|
|
50% of Group's planned 2PD production |
Commodity capped swap: swap component |
Oct 2023 - Sep 2025 |
Weighted average price of US$70.29/bbl |
Cash flow |
10,985 |
- |
- |
21. WARRANTS LIABILITY
On 6 June 2023, as part of the underwritten placing of additional ordinary shares, the Company entered into a warrant instrument with Tyrus Capital Event S.à.r.l ("Tyrus") for 30 million ordinary shares at an exercise price of 50 pence per share. The warrants are exercisable within 36 months from the date of issuance, with an expiry date of 5 June 2026. Management has applied the Black-Scholes option-pricing model to estimate the fair value of the warrants.
22. SEGMENT INFORMATION
Information reported to the Group's Chief Executive Officer (the chief operating decision maker) for the purposes of resource allocation is focused on two reportable/business segments driven by different types of activities within the upstream oil and gas value chain, namely producing assets and secondly development and exploration assets. The geographic focus of the business is on Southeast Asia ("SEA") and Australia.
Revenue and non-current assets information based on the geographical location of assets respectively are as follows:
|
|
Producing assets |
|
Exploration/ development |
|
|
|
|
||
|
|
Australia USD'000 |
|
SEA USD'000 |
|
SEA USD'000 |
|
Corporate USD'000 |
|
Total USD'000 |
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended 30 June 2023 (unaudited) |
|
|
|
|
|
|
|||
|
Revenue |
|
|
|
|
|
|
|
|
|
|
Liquids revenue |
62,810 |
|
22,789 |
|
- |
|
- |
|
85,599 |
|
Gas revenue |
- |
|
1,061 |
|
- |
|
- |
|
1,061 |
|
|
|
|
|
|
|
|
|
|
|
|
|
62,810 |
|
23,850 |
|
- |
|
- |
|
86,660 |
|
|
|
|
|
|
|
|
|
|
|
|
Production cost |
(70,084) |
|
(20,566) |
|
- |
|
- |
|
(90,650) |
|
DD&A |
(23,053) |
|
(1,257) |
|
(113) |
|
(151) |
|
(24,574) |
|
Administrative staff costs |
(7,066) |
|
(3,169) |
|
(974) |
|
(4,329) |
|
(15,538) |
|
Other expenses |
(2,103) |
|
(1,111) |
|
(778) |
|
(4,454) |
|
(8,446) |
|
Other income |
4,299 |
|
56 |
|
- |
|
435 |
|
4,790 |
|
Finance costs |
(6,856) |
|
(1,523) |
|
(1,283) |
|
(12,855) |
|
(22,517) |
|
|
|
|
|
|
|
|
|
|
|
|
Loss before tax |
(42,053) |
|
(3,720) |
|
(3,148) |
|
(21,354) |
|
(70,275) |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to non- current assets |
79,647 |
|
84,731 |
|
24,145 |
|
500 |
|
189,023 |
|
|
|
|
|
|
|
|
|
|
|
|
Non-current assets |
429,091 |
|
200,042 |
|
139,126 |
|
28,431 |
|
796,690 |
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended 30 June 2022 (unaudited) (Restated)* |
|
|
|
|
|||||
|
Revenue |
|
|
|
|
|
|
|
|
|
|
Liquids revenue |
175,476 |
|
48,256 |
|
- |
|
- |
|
223,732 |
|
Hedging income |
- |
|
1,907 |
|
- |
|
- |
|
1,907 |
|
|
|
|
|
|
|
|
|
|
|
|
|
175,476 |
|
50,163 |
|
- |
|
- |
|
225,639 |
|
|
|
|
|
|
|
|
|
|
|
|
Production costs |
(58,792) |
|
(34,191) |
|
- |
|
- |
|
(92,983) |
|
DD&A |
(33,065) |
|
(1,771) |
|
(117) |
|
(182) |
|
(35,135) |
|
Administrative staff costs |
(7,239) |
|
(2,023) |
|
(1,189) |
|
(4,714) |
|
(15,165) |
|
Other expenses |
(2,225) |
|
(619) |
|
(663) |
|
(1,996) |
|
(5,503) |
|
Other income |
3,281 |
|
54 |
|
14 |
|
349 |
|
3,698 |
|
Finance costs |
(3,397) |
|
(1,173) |
|
(200) |
|
(14) |
|
(4,784) |
|
Other financial gains |
1,904 |
|
- |
|
- |
|
- |
|
1,904 |
|
|
|
|
|
|
|
|
|
|
|
|
Profit/(Loss) before tax |
75,943 |
|
10,440 |
|
(2,155) |
|
(6,557) |
|
77,671 |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to non- current assets |
12,303 |
|
322 |
|
2,829 |
|
67 |
|
15,521 |
|
|
|
|
|
|
|
|
|
|
|
|
Non-current assets |
340,355 |
|
58,444 |
|
93,650 |
|
604 |
|
493,053 |
*Certain H1 2022 comparative information has been restated. Please refer to Note 25.
|
|
Producing assets |
|
Exploration/ development |
|
|
|
|
|||
|
|
Australia USD'000 |
|
SEA USD'000 |
|
SEA USD'000 |
|
Corporate USD'000 |
|
Total USD'000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Twelve months ended 31 December 2022 (audited) |
|
|
|
|
|
|
||||
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
Liquids revenue |
328,863 |
|
89,620 |
|
- |
|
- |
|
418,483 |
|
|
Gas revenue |
- |
|
3,119 |
|
- |
|
- |
|
3,119 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
328,863 |
|
92,739 |
|
- |
|
- |
|
421,602 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost |
(189,041) |
|
(61,659) |
|
- |
|
- |
|
(250,700) |
|
|
DD&A |
(57,835) |
|
(3,405) |
|
(235) |
|
(359) |
|
(61,834) |
|
|
Administrative staff costs |
(13,839) |
|
(4,073) |
|
(2,020) |
|
(9,286) |
|
(29,218) |
|
|
Other expenses |
(8,872) |
|
(1,877) |
|
(8,188) |
|
(3,368) |
|
(22,305) |
|
|
Impairment |
- |
|
(13,534) |
|
- |
|
- |
|
(13,534) |
|
|
Other income |
24,226 |
|
2,718 |
|
965 |
|
124 |
|
28,033 |
|
|
Finance costs |
(6,698) |
|
(2,033) |
|
(903) |
|
(1,774) |
|
(11,408) |
|
|
Other financial gains |
1,904 |
|
- |
|
- |
|
- |
|
1,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Profit/(Loss) before tax |
78,708 |
|
8,876 |
|
(10,381) |
|
(14,663) |
|
62,540 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to non- current assets |
110,405 |
|
582 |
|
23,266 |
|
69 |
|
134,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current assets |
424,017 |
|
101,835 |
|
115,390 |
|
231 |
|
641,473 |
|
Non-current assets in the table comprises oil and gas properties, intangible exploration assets, right-of-use assets, investment in associate, other receivables and prepayment, plant and equipment used in corporate offices and cash and cash equivalents. Deferred tax assets are excluded from the segmental note but included in the Group's consolidated statement of financial position.
Revenue arising from producing assets relates to the Group's single customer with respect to oil sales in Australia, and a different single customer for oil and gas sales in Malaysia. There is an active market for the Group's oil and gas production.
23. EVENTS AFTER THE REPORTING PERIOD
Montara operations update
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.
24. RELATED PARTY TRANSACTIONS
Placement of additional shares
On 7 June 2023, the Company completed an equity fundraising, creating an additional 94,081,826 ordinary shares at £0.45 per share, of which a placing and subscription of 1,769,135 new ordinary shares were acquired by the Directors of the Company for a total consideration of US$0.7 million.
25. RESTATEMENT AND RECLASSIFICATION OF COMPARATIVE FIGURES
Certain comparative figures in the consolidated financial statements of the Group have been restated arising from a change in accounting policy as well as reclassifications to conform to the presentation in the current period and to better reflect the nature of the respective items in the Group's consolidated financial statements.
The prior period restatement made was in relation to the change in accounting policy on the measurement of under/overlift, from recorded at the prevailing market price to recorded at the lower of cost and net realisable value as disclosed in Note 2.
The reclassifications made in the consolidated statement of financial position are related to the restricted cash held by the Group in relation to deposits placed for bank guarantees with respect to the PenMal Assets and Australian office buildings as a result of the April 2022 IFRIC Agenda item "Demand Deposits with Restrictions on Use arising from a Contract with a Third Party (IAS 7 Statement of Cash Flows). Additionally, the Group reclassed the fair value proceeds received from the issuance of shares to share premium account. The reclassifications do not impact the consolidated statement or profit or loss and other comprehensive income and consolidated statement of cash flows.
The reclassifications made in the consolidated statement of cash flows are related to the placement of decommissioning trust fund for the CWLH Assets, placement of abandonment cess fund for the PenMal Assets and interest paid, which are now classified in accordance to the nature of activities. The reclassifications do not impact the consolidated statement or profit or loss and other comprehensive income and consolidated statement of financial position.
The restatements and reclassifications impact the following items:
|
|
|
As previously reported USD'000 |
|
Restatements and reclassifications USD'000 |
|
As restated and reclassified USD'000 |
|
|
|
|
|
|
|
|
|
Consolidated statement of profit or loss and other comprehensive income for the period ended 30 June 2022 |
|
|
|
|
|
|
|
Production costs |
|
(83,401) |
|
(9,582) |
|
(92,983) |
|
Other income |
|
5,602 |
|
(1,904) |
|
3,698 |
|
Other financial gains |
|
- |
|
1,904 |
|
1,904 |
|
Income tax expense |
|
(37,767) |
|
3,641 |
|
(34,126) |
|
|
|
|
|
|
|
|
|
Consolidated statement of financial position as at 30 June 2022 |
|
|
|
|
|
|
|
Deferred tax assets |
|
14,366 |
|
5,683 |
|
20,049 |
|
Trade and other receivables |
|
28,588 |
|
(14,955) |
|
13,633 |
|
Cash and cash equivalents - non-current |
|
- |
|
621 |
|
621 |
|
Cash and cash equivalents - current |
|
161,628 |
|
(621) |
|
161,007 |
|
Share capital |
|
1,229 |
|
(870) |
|
359 |
|
Share premium account |
|
- |
|
870 |
|
870 |
|
Retained earnings |
|
11,553 |
|
(9,272) |
|
2,281 |
|
|
|
|
|
|
|
|
|
Consolidated statement of cash flows for the period ended 30 June 2022 |
|
|
|
|
|
|
|
Profit before tax |
|
87,253 |
|
(9,582) |
|
77,671 |
|
Increase in trade and other receivables |
|
10,505 |
|
9,751 |
|
20,256 |
|
Interest paid - operating activities |
|
(600) |
|
600 |
|
- |
|
Placement of abandonment cess fund for PenMal Assets |
|
- |
|
(169) |
|
(169) |
|
Interest paid - financing activities |
|
- |
|
(200) |
|
(200) |
|
Interest on lease liabilities paid - financing activities |
|
- |
|
(400) |
|
(400) |
|
|
|
|
|
|
|
|
|
Consolidated statement of cash flows for the year ended 31 December 2022 |
|
|
|
|
|
|
|
(Increase)/Decrease in trade and other receivables |
|
(214) |
|
41,397 |
|
41,183 |
|
Placement of decommissioning trust fund for CWLH Assets |
|
- |
|
(41,000) |
|
(41,000) |
|
Placement of abandonment cess fund for PenMal Assets |
|
- |
|
(397) |
|
(397) |
Glossary
|
£ |
British pound sterling |
|
2P |
the sum of proved and probable reserves, reflecting those reserves with 50% probability of quantities actually recovered being equal or greater to the sum of estimated proved plus probable reserves |
|
AAKBNLP |
Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields |
|
AIM |
Alternative Investment Market |
|
ARO |
Asset retirement obligations |
|
API |
American Petroleum Institute gravity |
|
bbl |
barrel
|
|
bbls/d |
barrels per day
|
|
boe |
barrels of oil equivalent
|
|
boe/d |
barrels of oil equivalent per day |
|
DD&A |
depletion, depreciation and amortisation |
|
EBITDAX |
earnings before interest tax, depreciation, amortisation and exploration |
|
FPSO |
floating production storage and offloading |
|
GHG |
greenhouse gases |
|
IFRS |
International Financial Reporting Standards |
|
LPG |
Liquefied petroleum gas |
|
mcf |
thousand cubic feet of natural gas |
|
mm |
million |
|
mmbbls |
million barrels |
|
mmboe |
million barrels of oil equivalent |
|
NOPSEMA |
National Offshore Petroleum Safety and Environmental Management Authority |
|
opex |
operating expenditures |
|
PETRONAS |
Petroliam Nasional Berhad |
|
PITA |
Petroleum Income Tax |
|
PRRT |
Petroleum Resource Rent Tax |
|
PSC |
production sharing contract
|
|
RBL |
reserves based loan |
|
reserves |
hydrocarbon resource that is anticipated to be commercially recovered from known accumulations from a given date forward |
|
US$ or USD |
United States dollar |
The technical information contained in this announcement has been prepared in accordance with the June 2018 guidelines endorsed by the Society of Petroleum Engineers, World Petroleum Congress, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers Petroleum Resource Management System.
A. Shahbaz Sikandar of Jadestone Energy plc, Group Subsurface Manager with a Masters degree in Petroleum Engineering, and who is a member of the Society of Petroleum Engineers and has worked in the energy industry for more than 25 years, has read and approved the technical disclosure in this regulatory announcement.
The information contained within this announcement is considered to be inside information prior to its release, as defined in Article 7 of the Market Abuse Regulation No. 596/2014 which is part of UK law by virtue of the European Union (Withdrawal) Act 2018, and is disclosed in accordance with the Company's obligations under Article 17 of those Regulations.
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