2024 Half Year Results

 

17 September 2024-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 2024 (the "financial statements").  

 

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

 

Key updates:

 

l Akatara development project achieved mechanical completion in June 2024, with sales gas production commencing in July 2024 and reaching c.14mmscf/d. Production has been recently curtailed by a small mechanical issue in the gas processing facility's refrigeration compressors, with repairs underway. These repairs and their associated cost remain the responsibility of the EPCI contractor.

l Positive progress on the Montara oil storage tank repair and maintenance programme, which has allowed for the permanent stationing of shuttle tanker at the field to be discontinued in late-August, earlier than expected.   

l Year-to date 2024 production (to end August 2024) has averaged c.17,500 boe/d, a c.42% increase year-on-year due to the success of both organic and acquisition driven growth over the period. Annual 2024 production guidance is reiterated at 18,500 - 21,000 boe/d, with an expected outcome towards the lower end of the range, given year-to-date production and ongoing Akatara activities.

l Operating expenditure guidance for 2024 is reiterated at US$240-280 million (excluding forecast royalties and carbon taxes of c.US$30 million),

l Capital expenditure and other cash expenditure guidance is unchanged at US$80-110 million and US$62 million respectively,

l US$31.1 million loss after tax for the first half of 2024, which includes a US$45.8 million non-cash charge to production costs related to the CWLH 2 acquisition, which closed in February 2024.

l Net debt of US$69.1 million at 30 June 2024 reflects c.US$130.9 million of consolidated Group cash balances and US$200.0 million of debt drawn under the Group's reserves-based lending ("RBL") facility.  As at 31 August 2024, net debt was US$94.6 million, based on consolidated Group cash balances of US$105.4 million and US$200.0 million of debt drawn under the RBL facility. The Group expects to receive c.US$57 million of proceeds in September relating to August liftings. The Group's US$31.9 million working capital facility was undrawn at the end of the period.

 

Paul Blakeley, President and CEO commented:

 

"Increased production, coupled with robust price realisations and flat underlying operating costs, resulted in an improving financial performance in the first half of 2024, with adjusted EBITDAX and operating cash flows significantly higher year-on-year.

 

Our first half performance also benefited from the increasing diversification of the portfolio as we build greater reliability and resilience. The adverse weather which impacted our Australia production early in the year was offset by higher production from Malaysia, an increase in our CWLH interest and strong output from Sinphuhorm. Montara performance continues to improve with greater facility reliability year-to-date, and good progress on the FPSO tank and repair programme, which allowed us to release the temporary storage tanker at Montara a few months earlier than planned.  We also added a medium-term growth option by signing the SFA Cluster PSC offshore Malaysia, and we continue to work hard on a gas sales agreement for our Vietnam resource.

 

Jadestone's primary focus so far in 2024 has been the completion and commissioning of the Akatara development project onshore Indonesia. The construction phase was completed on schedule at the end of the second quarter, followed by the start of both gas and condensate sales. Notwithstanding the current curtailment of production for a repair to the plant's refrigeration compressors, the progress at Akatara, including an excellent safety record, is a major step forward for the Group, and will diversify our cash flow generation with more low cost and high value production."

 

 

 

2024 FIRST HALF RESULTS SUMMARY

 

USD'000 except where indicated	Six months ended 30 June 2024	Six months ended 30 June  2023	Twelve months ended 31 December 2023
Total hours worked lost time injury free (million)	3.85	1.45	4.55
Total recordable injury rate	3.12	0.00	0.86
Production, boe/day1	16,867	12,339	13,813
Realised oil price per barrel of oil equivalent (US$/boe)2	88.73	86.15	87.34
Realised gas price per thousand standard cubic feet     (US$/mscf)	1.64	1.41	1.53
Revenue3	185,060	86,660	309,200
Production costs	(136,324)	(90,650)	(232,772)
Adjusted unit operating costs per barrel of oil equivalent     (US$/boe)4	31.72	40.27	37.24
Adjusted EBITDAX4	60,215	(3,127)	90,647
Loss after tax	(31,119)	(59,934)	(91,274)
Loss per ordinary share: basic and diluted (US$)	(0.06)	(0.13)	(0.18)
Operating cash flows before movement in working capital	27,946	(24,179)	36,499
Capital expenditure	47,618	23,807	115,882
Net (debt)/cash4	(69,131)	7,782	(3,596)

 

Operational and financial summary  

 

l Zero lost time injuries in operated and non-operated assets. This involved working 3.85 million manhours in operated assets (H1 2023: 1.45 million manhours), an increase of 165% from H1 2023.

l Zero Tier 1 or Tier 2 process safety events, with a focus on pre commissioning activities at Akatara and ongoing asset integrity programs at operated assets.

l Production increased by 37% in H1 2024, reaching 16,867 boe/d, up from 12,339 boe/d in H1 2023. The increase was due to higher production from PenMal following the successful drilling campaign in late 2023, a higher working interest in the CWLH following completion of the acquisition of an additional 16.67% working interest  in February 2024,  full production from Sinphuhorm, acquired in February 2023, and a full period of production from Montara, compared to H1 2023 when production was shut in for much of the first quarter. These increases were partially offset by lower production at Stag compared to the prior period, impacted by extensive weather-related downtime in Q1 2024, a planned maintenance shutdown and underperformance of downhole pumps, which have required more frequent workovers than planned.

l Oil liftings totaled 2.2 mmbbls in H1 2024, more than double H1 2023 of 1.1 mmbbls, primarily driven by increased production described above and the addition of an underlift position at CWLH as part of the February 2024 acquisition, which subsequently formed part of a lifting in March 2024.

l The average oil price realisation, excluding the effect of hedging for H1 2024, was US$88.73/bbl, a 3.0% increase from US$86.15/bbl in H1 2023. This increase was driven by a higher realised Brent price, which rose by 8.9%, to US$84.14/bbl from US$77.28/bbl in H1 2023. The higher realised Brent price was offset by a reduction in the premium to US$4.59/bbl in H1 2024, from US$8.87/bbl in H1 2023. This decrease was due to the composition of liftings, with lower liftings at Stag (which attracts the highest premium of Jadestone's production), and higher lifted volumes at CWLH, which has a lower premium.

l H1 2024 revenue totalled US$185.1 million, a 113% increase on H1 2023, reflecting the increase in lifted volumes and price realisations described above. H1 2024 revenue reflects a hedging charge of US$15.4 million from commodity swap contracts entered in support of the execution of reserves-based lending ("RBL") facility;

 

 

l The CWLH 2 acquisition impacted revenues and production costs in H1 2024 by US$45.8 million (2023: Nil), reflecting the market value of the under-lift obtained after acquiring an additional 16.67% interest in the CWLH assets (combined interest 33.34%) in February 2024. The US$45.8 million in production costs is a non-cash item arising from the purchase price allocation required under acquisition accounting standards. The underlift was sold as part of the March 2024 lifting realising US$45.8 million.

l Production costs, excluding the movement in inventory and the under-lift impacts, decreased by 0.7%, from US$116.4 million in H1 2023 to US$115.5 million in H1 2024.

l As at 30 June 2024, closing crude inventories totalled 442,781 bbls, and the Group had an underlift position of 270,449 bbls. After the H1 2024 reporting period, the Group generated US$53.0 million in revenues from three liftings of 0.59 mmbbls in July from Montara, Stag and PenMal;

l Adjusted EBITDAX increased to US$60.2 million from a loss of US$3.2 million in H1 2023, mostly due to higher revenue;

l Net loss after tax in H1 2024 of US$31.1 million (H1 2023: US$59.9 million net loss);

l Operating cash flow before movements in working capital significantly improved in H1 2024 to US$27.9 million from an outflow of US$24.2 million in H1 2023, reflecting the trends described above;

l Capital expenditure in H1 2024 of US$47.6 million, an increase of 100% compared to H1 2023 (at US$23.8 million) primarily due to higher expenditure for the Akatara development project onshore Indonesia as it entered the final phase of commission and completion; and

l Net debt balance of US$69.1 million as at 30 June 2024 (H1 2023: US$7.8 million net cash), reflecting a drawdown of US$200.0 million from the RBL facility and total cash and cash equivalents of US$130.9 million.

 

¹ Production includes the Sinphuhorm Asset gas production in accordance with Petroleum Resource Management Systems guidelines, non-IFRS measures. However, in accordance with IAS 28 the investment is accounted for as an associated undertaking and only recognises the share of results of associate. 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, excluding the effect of hedging.

³Revenue in H1 2024 and YE 2023 include hedging loss of US$15.4 million and US$10.3 million respectively from the commodity swap contracts entered into in support of the RBL facility.

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

 

For further information, please contact:

 

Jadestone Energy plc
Paul Blakeley, President and CEO	+65 6324 0359 (Singapore)
Bert-Jaap Dijkstra, CFO Phil Corbett, Head of Investor Relations	+44 (0) 7713 687467 (UK)
	ir@jadestone-energy.com
Stifel Nicolaus Europe Limited (Nomad, Joint Broker)	+44 (0) 20 7710 7600 (UK)
Callum Stewart
Jason Grossman
Ashton Clanfield
Peel Hunt LLP (Joint Broker)	+44 (0) 20 7418 8900 (UK)
Richard Crichton
David McKeown Georgia Langoulant
Camarco (Public Relations Advisor)	+44 (0) 203 757 4980 (UK)
Billy Clegg	jse@camarco.co.uk
Georgia Edmonds Elfie Kent

 

 

 

 

 

Webcast

 

The Company will host an investor and analyst presentation at 9:00 a.m. (BST) on Tuesday, 17 September 2024, including a question-and-answer session, accessible through the link below:

 

Webcast link: https://www.investis-live.com/jadestone-energy/66c5c57a7caa6c19003474c9/maert

  

Event title: Jadestone Energy plc first-half 2024 results

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

Date: 17 September 2024

 

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=70236

Access Code: 288973

 

 

 

 

 

ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG")

 

Jadestone is committed to being a responsible operator, that contributes to an orderly energy transition by helping to meet regional energy demand, whilst bringing positive social and economic benefits for its stakeholders, local communities and the people associated with its operations. Progress made during the half year ended 30 June 2024 is set out below across Jadestone's priority ESG areas.

 

HSE Governance

 

The Group continued its strong safety performance in the first year half of 2024 despite elevated levels of activity at the Akatara project. The Group reported no life altering events or significant impact to the environment, no regulatory enforcements notices, no Tier 1 or 2 process safety loss of primary containment events but one lost time injury (LTI). Jadestone's combined operations worked over 3.8 million manhours in H1 2024. The lost time injury related to staff sustaining a shoulder injury which required minor surgery.

 

Of note is the safety record at the Akatara gas development project site onshore Sumatra, Indonesia, which achieved the major milestones of mechanical completion and introduction of feed gas from wells, which signalled the commencement of commissioning activities in June 2024. The project has achieved 7.4 million manhours with no LTI reported. Commissioning saw the site transition from a construction site to a facility producing hydrocarbons, requiring a change in how work is planned and executed.  As at the end of June, there had been no process safety loss of primary containment events associated with commissioning, with ongoing activities to ensure controls are effectively implemented. Whilst the site currently remains formally under the control of the EPCI contractor, a detailed Operational Readiness program has been undertaken by the Company to ensure that when the performance test is completed, and the facility is formally handed over, Jadestone Energy is ready to safely operate the facility.

 

The Montara Venture FPSO tank inspection and repair program has been progressing well, following a Prohibition Notice issued by the regulator in June 2022. All tanks have been inspected and repairs are ongoing.  Jadestone continues to engage closely and transparently with the regulator about the progress of the inspection and repair work and as each tank is completed, a Technical File Note is issued to the regulator which allows the tank to be released from the Prohibition Notice. 

 

Net Zero interim targets

 

Jadestone's strategy for maximising reserves from existing producing oil and gas fields explicitly precludes frontier exploration and new greenfield development, a position that is in line with the IEA's Net Zero Emissions by 2050 Scenario. The Group is well positioned to remain relevant in the face of energy transition as a responsible steward of mid-life assets divested by larger companies, committed to upholding climate targets and executing its Net Zero by 2040 pledge.

 

The Company is committed to reduce Scope 1 and 2 absolute GHG emissions from its operated assets by 20% by 2026 and by 45% by 2030 (from 2021 levels) on its pathway to Net Zero by 2040. These interim targets will be achieved through a combination of measures, including minimising flaring, methane quantification, monitoring and reduction as well as reliance on carbon credits within the regulatory schemes of Jadestone's operating regions. For details of Jadestone's Net Zero GHG reduction plan, please refer to the 2023 Sustainability Report.

 

Group's H1 2024 Scope 1 GHG emissions¹ during H1 2024 were slightly below plan, due to operations at Stag being affected by monsoon activity and flaring reduction initiatives at Montara. At the Montara site, a 33% reduction on flaring emissions compared to workplan and budget was achieved in H1 2024, due to a heightened focus on minimisation of flaring during normal production as part of a three-step flare optimisation plan for Montara. This plan involves:

 

 

 

 

¹ Includes Montara, Stag and PenMal sites; Jadestone will integrate GHG emissions from the Akatara Gas field operations in the Full Year 2024 report.

 

 

·      Reinjection compressor ("RIC") control logic modifications and automation of the injection choke, with the scope completed in May 2024, resulting in historically low flare rates post completion;

·      Continued focus on reliability of the RIC resulting in significant improvement in RIC uptime during H1 2024;

·      Feasibility analysis into increasing the capacity of the RIC. The engineering studies have commenced and will be completed during H2 2024.

 

These initiatives are an important cornerstone of Jadestone's Net Zero implementation roadmap to 2030.

 

The Company continues to build a fit-for-purpose Leak Detection and Repair programme across all operated assets and targets the introduction of annual leak detection and repair ("LDAR") at each operated site by the end of 2024¹.

 

Governance

 

Jadestone's Board underwent a number of changes during the first quarter of 2024, with the longer-term objective to ensure that the Board is sized appropriate to the Company's scale and ambition, while maintaining the right capabilities and adhering to corporate governance standards.

 

On 25 January 2024, the Company announced the appointment of Joanne Williams as an independent non-executive director. Ms. Williams is the Chair of both the HSEC Committee and the Montara Technical Committee, and a member of the Audit Committee and the Disclosure Committee. 

 

On 25 March 2024, the Company announced the appointment of Adel Chaouch as an independent non-executive director. On the same day, the Company announced the resignation of Lisa Stewart as an independent non-executive director and Robert Lambert as an independent non-executive director.

 

On 27 March 2024, the Company announced the resignation of Dennis McShane as an independent non-executive director and Chair of the Board.  On the same day, the Company announced the election of Adel Chaouch as the Chairman of the Board. Mr. Chaouch is the Chairman of the Governance and Nomination Committee, and a member of the Remuneration Committee.

 

On 9 May 2024, the Company announced the appointment of Linda Beal as an independent non-executive director. Ms. Beal is the Chair of the Audit Committee, replacing Iain McLaren who, in line with previous announcements, did not seek re-election at the Company's Annual General Meeting and formally stepped down on 13 June 2024. Ms. Beal is a member the Governance and Nomination Committee and the Remuneration Committee.

 

Effective 12 June 2024, Joanne Williams and David Neuhauser joined the CEO and CFO on the Disclosure Committee.

 

On 3 July 2024, the Company announced that Bert-Jaap Dijkstra, Executive Director and Chief Financial Officer ("CFO"), has decided to leave the Company. Mr. Dijkstra will remain in his post during the publication of the Company's 2024 Half-Year Results and support the October 2024 redetermination of the Company's reserve-based lending facility.

 

The Company is currently making good progress on both appointing a replacement CFO and the ongoing search for a Chief Operating Officer.

 

 

 

 

 

 

 

 

 

 

¹ With an exception of Lemang, which will have an LDAR exercise implemented within 12 months of starting operations.

 

Producing assets

 

Australia

 

Montara Project (100% working interest, operator)

 

The Montara fields averaged 4,951 bbls/d in H1 2024, compared to 2,931 bbls/d in H1 2023. The year-on-year increase is primarily explained by Montara production being shut in during the start of 2023 until late March 2023 for repairs and maintenance activity on the Montara Venture FPSO's storage tanks.

 

Production during the first half of 2024 was impacted by the cyclone season early in the year, and the temporary shut in of the H6 and Swift-2 wells pending repairs. Both wells were brought back online early in the second half of 2024.  

 

The Montara Venture FPSO tank inspection and repair programme is progressing well, resulting in increased oil storage capacity. This has allowed for the shuttle tanker operation, which had been in place to provide operational flexibility for Montara during the repair programme, to cease in late August 2024, earlier than planned.

 

The Group is progressing its plans to re-drill the Skua-11 well. This well is expected to boost Montara production through reinstating production from the Skua-11 well and is also targeting additional reserves in the Skua structure.

 

In total, three cargoes totalling c.0.8 mmbbls (H1 2023: one cargo of c.0.3 mmbbls) were lifted from Montara in the first half of 2024, with an average oil price realisation of US$88.35/bbl, excluding the effect of hedging (consisting of an average Brent price of US$83.82/bbl and average premium of US$4.53/bbl). This compares to an average realisation of US$76.05/bbl in H1 2023 (Brent US$74.69/bbl and premium US$1.36/bbl). A further lifting of c.0.2 mmbbls was completed in early July 2024.

 

CWLH (33.33% working interest)

 

On 14 February 2024, the Group completed the acquisition of an additional 16.67% working interest in the Cossack, Wanaea, Lambert and Hermes oil fields ("CWLH") offshore western Australia, doubling its working interest to 33.33%.

 

During the first half of 2024, Jadestone's net production from the CWLH fields averaged 2,951 bbls/d, compared to 1,569 bbls/d in H1 2023. The year-on-year change is primarily explained by the increase in the Group's working interest referenced above.

 

Following engagement with the CWLH joint venture, total abandonment trust fund payments associated with the acquisition of the additional 16.67% interest completed in early 2024 have been revised down to US$83.8 million. The Group contributed US$65.0 million to the CWLH Abandonment Trust Fund during H1 2024 in connection with the CWLH acquisition, with the final trust fund payment of US$18.8 million expected to be paid at the end of 2024.

 

The Group lifted one cargo of c.0.7 mmbbls in the first half for an average oil price realisation of US$86.39/bbl, excluding the effect of hedging (H1 2023: no liftings net to the Jadestone) based on a Brent price of US$85.49/bbl with a premium of US$0.90/bbl. Due to the acquisition of an additional 16.67% share in CWLH and the ongoing good performance of the CWLH fields, a further cargo of c.0.7 mmbbls was lifted in August 2024.

 

Stag (100% working interest, operator)

 

The Stag field averaged 1,921 bbls/d in the first half of 2024, compared to 2,879 bbls/d in H1 2023. The first half of 2023 benefited from the onset of production of the Stag-50H and 51H wells drilled in late 2022. Stag field production in H1 2024 reflected greater than normal weather-related downtime in Q1 2024, a planned maintenance shutdown and mechanical issues in several wells which required workovers.

 

The Group continues to review options for further infill wells on the Stag field.

 

The Group sold one c.0.2 mmbbls cargo (H1 2023: two cargoes totalling c.0.5 mmbbls) of Stag crude in the first half of 2024. Premiums for Stag crude have remained robust, with the H1 2024 cargo being sold at US$101.37/bbl, based on average oil price realisation of US$85.49/bbl, excluding the effect of hedging, plus a premium of US$15.88/bbl. A further cargo of Stag crude was sold after the period end for a premium of US$10.69/bbl.

Malaysia

 

PM323 PSC (60% working interest, operator)

 

The PM323 PSC produced an average of 3,839 bbls/d net to Jadestone's working interest in H1 2024 (H1 2023: 1,667 bbls/d). The year-on-year increase is a result of the positive impact of the Group's infill drilling programme on the East Belumut field in late-2023.

 

The Group is progressing plans for further infill drilling on the East Belumut field, in particular focusing on the undrained southwestern area of the field discovered during the 2023 campaign.

 

A total of c.0.4 mmbbls (H1 2023: 0.1mmbbls) were lifted from the PM323 PSC in the first half of 2024, with an average oil price realisation of US$86.75/bbl (H1 2023: US$83.31/bbl) based on a Brent price of US$82.62/bbl (H1 2023: US$79.93/bbl) and a premium of US$4.14/bbl (H1 2023: US$3.38/bbl).

 

PM329 PSC (70% working interest, operator)

 

The PM329 PSC produced an average of 1,616 boe/d net to Jadestone's working interest in H1 2024, consisting of 1,103 bbls/d of oil and 3.1 mmscf/d of gas (H1 2023: 2,212 boe/d, consisting of 1,518 bbls/d of oil and 4.2 mmscf/d of gas). The year-on-year decrease is primarily explained by natural decline.

 

A total of c.0.1 mmbbls (H1 2023: 0.2mmbbls) of oil were lifted from the PM323 PSC in the first half of 2024, with an average oil price realisation of US$86.76/bbl (H1 2023: US$83.31/bbl), based on a Brent price of US$82.62/bbl (2023: US$79.93/bbl) and a premium of US$4.14/bbl (2023: US$3.38/bbl). In addition, c.0.6 bcf of gas was sold at an average realisation of US$1.64/mscf.

 

SFA Cluster (100% working interest, operator)

 

In July 2024, Jadestone was awarded a 100% participating interest in a Small Field Asset Production Sharing Contract (the "SFA Cluster PSC") offshore Peninsular Malaysia. The SFA Cluster PSC covers an area of 348km² in shallow water offshore Peninsular Malaysia located adjacent to the Group's existing operated PM323 and PM329 PSCs, and is surrounded by the PM428. The SFA Cluster PSC contains the Penara, Puteri-Padang and North Lukut fields, assets in which Jadestone initially acquired a non-operated interest at the time of the Group's entry into Malaysia in August 2021.

 

Jadestone currently estimates that the SFA Cluster PSC contains c.15 mmbbls of gross 2C contingent resources. Leveraging the experience gained through the successful 2023 infill drilling campaign on the PM323 licence, Jadestone believes there is the potential for significant upside from future infill drilling across the existing SFA Cluster fields, as well as opportunities on the surrounding PM428 PSC. The Group intends to continue its technical assessment of the SFA Cluster prior to submission of a field development and abandonment plan to PETRONAS.

 

PM428 PSC (60% working interest, operator)

 

In January 2024, Jadestone was awarded a 60% operated interest in the PM428 PSC offshore Peninsular Malaysia. The PM428 PSC is adjacent to the PM323 and PM329 PSCs, and surrounds the SFA Cluster PSC (referenced above). The PM428 PSC carries a US$0.5 million financial commitment to reprocess existing seismic and contains a number of prospects which, in a success case, could be developed through existing infrastructure currently operated by Jadestone.

 

Indonesia

 

Akatara gas development (100% working interest[1], operator)

 

The Akatara gas development is located within the Lemang Production Sharing Contract onshore Sumatra in Indonesia. Akatara was previously developed as an oil field, prior to being redeveloped by Jadestone to commercialise gas, condensate and LPGs reserves in shallower zones.

 

Development activity at Akatara peaked in the first half of 2024. The focus during the period was on completing the installation of equipment and infrastructure at Akatara Gas Processing Facility ("AGPF"), tying in the development wells, facilities and flowline, followed by pre-commissioning, commissioning and start-up activities.

 

The workover campaign on the five existing Akatara wells, which provide gas to the AGPF, was successfully completed during the period, with the five wells flowing at an aggregate rate of 54 mmscf/d, significantly in excess of the c.25 mmscf/d of raw feed gas required under the gas sales agreement. In addition, the 8" diameter 17km pipeline exporting gas from the AGPF was successfully tested and tied into the regional gas trunkline.

 

A major milestone was reached on 22 June 2024 with declaration of Mechanical Completion at the AGPF and the introduction of reservoir gas from one of the five production wells, with condensate production also commencing at this point.

 

Commissioning of the facility continued into the second half of 2024, with commercial gas sales commencing on 31 July at a rate of c.4 mmscf/d, along with LPG production. During August, commercial gas sales reached c.14 mmscf/d, with production recently curtailed due to mechanical issues with the facility's refrigeration compressors, where repairs are currently underway.

 

Thailand

 

Sinphuhorm (9.52% working interest, non-operated)

 

During the first half of 2024, the Sinphuhorm field produced an average of 1,585 boe/d (1,565 boe/d gas and 23 bbls/d of condensate). Production for the period 23 February 2023 (when Jadestone completed the acquisition of its Sinphuhorm interest) to 30 June 2023 averaged 1,531 boe/d, or 1,083 boe/d averaged over the first half of 2023.

 

Activity at the field during the first half of 2024 mainly comprised a booster compression project, which aims to sustain plateau production levels over the remaining life of the concession. The booster compression project was completed at the end of May 2024.

 

As this is an investment in associate, the Group does not recognise its share of revenues and production costs, instead recognising its share of results of associate. Dividends of US$3.8 million were received in H1 2024 (H1 2023: no dividends received). A further dividend of US$0.8 million was distributed early July 2024 after the period end.

 

 

Pre-production assets

 

Vietnam

 

Block 51 (100% working interest, operator) and Block 46/07 (100% working interest, operator) PSCs

 

In January 2024, the Group announced that it had signed a Heads of Agreement ("HoA") with PetroVietnam Gas Joint Stock Corporation for the Gas Sales and Purchase Agreement ("GSPA") relating to the Nam Du and U Minh ("NDUM") gas fields development, located in the Block 46/07 and Block 51 Production Sharing Contracts in shallow water offshore southwest Vietnam.

 

Following signature of the HoA, the Group commenced detailed negotiations over a fully termed GSPA, which are currently ongoing. The GSPA is also a precursor to the submission of an updated Field Development Plan for the Nam Du and U Minh fields, the approval of which is required before a Final Investment Decision can be taken. The Group is currently updating this FDP, which will specify the development concept for the NDUM fields, associated capital and operating cost estimates, and a schedule to first gas.

 

The Block 46/07 PSC includes a commitment to drill an exploration well.  This commitment has been extended several times from 2015 up to the end of June 2024. Historically, extension requests have been approved after expiry. An extension request was filed by the Company in February 2024 and is consistent with previous successful extensions, in that Jadestone proposes to drill this well as part of the development drilling for the Nam Du field development project.

 

The Tho Chu discovery in Block 51 was under a suspended development area status. The Group is working with Petrovietnam and other government entities to obtain a suspension of the relinquishment obligation for Block 51.

 

 

 

 

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 2024.

 

USD'000 except where indicated	Six months ended 30 June 2024	Six months ended 30 June 2023	Twelve months ended 31 December 2023
Production, boe/day1	16,867	12,339	13,813
Sales volume, barrels of oil equivalent (boe)	2,330,574	1,119,011	3,862,741
Realised oil price per barrel of oil equivalent   (US$/boe)2	88.73	86.15	87.34
Gas sales, thousand standard cubic feet (mscf)	559,888	752,660	1,366,505
Realised gas price per thousand standard cubic feet  (US$/mscf)	1.64	1.41	1.53
Revenue3	185,060	86,660	309,200
Production costs	(136,324)	(90,650)	(232,772)
Adjusted unit operating costs per barrel of oil   equivalent (US$/boe)4	31.72	40.27	37.24
Adjusted EBITDAX4	60,215	(3,127)	90,647
Unit depletion, depreciation & amortisation   (US$/boe)	13.02	13.15	14.14
Impairment of assets	-	-	(29,681)
Loss before tax	(29,129)	(70,275)	(102,766)
Loss after tax	(31,119)	(59,934)	(91,274)
Loss per ordinary share: basic and diluted   (US$)	(0.06)	(0.13)	(0.18)
Operating cash flows before movement in working   capital	27,946	(24,179)	36,499
Capital expenditure	47,618	23,807	115,882
Net (debt)/cash4	(69,131)	7,782	(3,596)

 

Benchmark commodity price and realised price

 

l The average oil price realisation, excluding the effect of hedging increased in H1 2024 by 3.0% to US$88.73/bbl, compared to US$86.15/bbl in H1 2023. The higher realised price was due benchmark Brent price increasing 8.9% to $84.14/bbl from $77.28/bbl in H1 2023. However, this gain was impacted by a reduction in average realised premium, which reduced to $4.59/bbl in H1 2024 from $8.87/bbl in H1 2023. This decrease was caused by the composition of liftings: Stag, with the highest premium, had lower lifting volumes, while CWLH, with a lower premium, had higher volumes lifted during the period.

 

 

 

 

 

¹ Production includes the Sinphuhorm Asset gas production in accordance with Petroleum Resource Management Systems guidelines, non-IFRS measures. 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, excluding the effect from hedging.

³ Revenue in H1 2024 and YE 2023 includes a hedging charge of US$15.4 million and US$10.3 million respectively from the commodity swap contracts entered into in support of the RBL facility.

⁴ Adjusted unit operating cost per boe, adjusted EBITDAX and net (debt)/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 recorded a 37% growth for H1 2024 with 16,867 boe/d compared to 12,339 boe/d in H1 2023. The overall increase of 4,528 boe/d was the result of the following factors:

 

·      Montara's production rose by 2,020 bbl/d, reflecting the phased restart that began in March 2023, which impacted H1 2023 output. In contrast, H1 2024 benefited from a full six months of production.

·      PenMal added 1,576 bbl/d following the successful PM323 infill drilling in late 2023, partially offset with natural field decrease at PM329. 

·      CWLH's production increased by 1,382 bbl/d following the completion of a second acquisition in February 2024, which doubled the working interest in the assets.

·      Sinphuhorm contributed an additional 508 boe/d in H1 2024, benefiting from a full six months of production compared to H1 2023, when the asset was acquired in February 2023; and

 

The above increase was partly offset by:

 

·      Stag decreased 958 bbls/d due to extended downtime caused by adverse weather conditions and increased workover activity due to mechanical issues in several wells which required workovers.

 

Lifted oil volumes were higher in H1 2024 compared to H1 2023 predominately due to:-

 

In mmbbls except where indicated	Six months ended 30 June 2024		Six months ended 30 June 2023	Remark
CWLH	0.7		-	One lifting immediately following the completion of second acquisition.
Montara	0.8		0.3	H1 2024 3 liftings vs H1 2023 1 lifting with phased production resumed in late March 2023.
Stag	0.2		0.5	One lifting in H1 2024 compared to two liftings in H1 2023.
PenMal	0.5		0.3	Successful drilling campaign led to higher production available for lifting nomination.
Total	2.2		1.1	H1 2024 10 liftings vs H1 2023 6 liftings.
PenMal gas sales  (mmscf)	559.9		752.7	Decrease in gas sales driven by natural decline at PM329 asset.

 

Revenue

 

The Group generated gross revenues before hedging results of US$200.5 million a 131% increase over the comparable period (H1 2023: US$86.7 million).

 

A commodity swap hedge resulted in a charge of US$15.4 million (H1 2023: nil), resulting in net revenue of US$185.1 million in H1 2024 (H1 2023: US$86.7 million).

 

The period-on-period increase in total net revenues of US$98.4 million is due to:

 

·     Higher lifted volumes, which resulted in an increase of US$111.4 million in H1 2024; inclusive of US$45.8 million from CWLH lifting of 530,484 bbls.

·   Increased average oil price realisation, excluding the effect of hedging of US$88.73/bbl in H1 2024 (compared to US$86.15/bbl in H1 2023), adding US$2.6 million to revenue;

·     Lower gas sales with reduced average gas price realisation of US$1.64/mscf in H1 2024 (compared to US$1.41/mscf in H1 2023) resulted in a decrease of US$0.2 million of revenue and;

·      Hedging resulted in a loss of US$15.4 million in H1 2024, with no impact in H1 2023, as the program commenced in H2 2023.

 

 

Production costs

 

Production costs in H1 2024 totalled US$136.3 million, a 50.3% increase from US$90.7 million in H1 2023. This US$45.7 million increase was primarily driven by changes in crude inventories and partner over/under lift imbalances. If movements in crude inventory and partner over/under lift imbalances are excluded there is a increase of $0.9 million, totaling $116.4 million compared to $115.5 million in H1 2023, indicating relatively constant underlying core operational expenses as detailed below:

 

		H1 2024 USD'000		H1 2023 USD'000		Variance USD'000		Note
Operating costs		53,693		52,562		1,131		(i)
Workovers		10,633		9,531		1,102		(ii)
Logistics		13,956		14,743		(787)		(iii)
Repairs and maintenance		28,090		28,378		(288)		(iv)
Tariffs and transportation costs		3,656		3,035		621		(v)
Supplementary payments and royalties		6,324		7,298	(	(974)		(vi)
Underlift, overlift and crude inventories    movement		19,972		(24,897)		44,869		(vii)
		136,324		90,650		45,674

 

(i)            Operating cost rose by US$1.1 million, or 2%, to US$53.7 million in H1 2024 from US$52.6 million (H1 2023). This increase between periods was mainly explained by:

-          CWLH operating costs increased by US$6.5 million, reflecting the acquisition of an additional 16.67% in February 2024, resulting in a total working interest of 33.33% from that point compared to 16.67% for H1 2023.

-            Stag shuttle tanker charter rates reduced by US$3.4 million compared to H1 2023.

-            Montara's operating costs decreased by US$4.6 million, from US$24.4 million in H1 2023 to US$19.8 million in H1 2024. This reduction was primarily due to lower diesel consumption at the Montara in H1 2024 compared to H1 2023 which required more diesel for FPSO and operation of compressor during wells shut-in and production start-up in late March 2023.

-               PenMal operating costs increase by US$2.6 million due to the rectification costs at Abu platform and additional operational expenses associated with the non-operated assets.

 

(ii)           Workover costs increased by US$1.1 million to US$10.6 million (H1 2023: US$9.5 million), with PenMal increasing US$0.7 million to improve well integrity and performance and US$0.4 million at Stag to carried out standard replacement for underperforming downhole pumps with 6 workovers during H1 2024 compared five in H1 2023.

 

(iii)          Logistics costs reduced by US$0.8 million to US$13.9 million (H1 2023: US$14.7 million), primarily due unavailability of helicopter for use at Montara hence lower standing cost incurred during H1 2024 by US$1.1 million, and a US$0.3 million reduction at PenMal, with decreased offshore activities at the Puteri cluster in H1 2024 compared to H1 2023.This decrease was offset by a US$0.6 million increase at Stag, caused by multiple cyclone events that necessitated more frequent use of support vessels and helicopter services compared to the same period year-ago.

 

(iv)          Repair and maintenance ("R&M") reduced US$0.3 million to US$28.1 million (H1 2023: US$ 28.4 million) due to a net increase at Stag of US$1.7 million for one-off remedial activities carried out on its calm buoy and an export pipeline inspection offset by a decrease of US$2.0 million due to reduced activities at PenMal SFA cluster compared to the same period year-ago.

 

(v)          Tariffs and transportation increased by US$0.7 million to US$ 3.7 million (H1 2023: US$3.0 million) predominately due to three cargo liftings from Montara in H1 2024 compared to one in H1 2023.

 

 

(vi)          Supplementary payment and royalties decreased US$1.0 million mainly reflecting the net movement from PenMal of US$2.5 million mainly due to lower realised prices compared to H1 2023. These supplementary payments are based on the differential between the realised price and the escalated PSC base price. This decrease was partially offset by an US$1.5 million increase in CWLH levies due to acquisition of the additional 16.67% ownership interest.

 

(vii)         Underlift, overlift, and crude inventory movements increased by US$44.9 million, primarily due to the purchase price accounting for the second acquisition of CWLH. The acquisition of the second tranche of CWLH increased production costs by US$45.8 million, attributable to the 530,484 bbls of underlift acquired. This underlift was sold in March 2024, and the cost associated with acquiring the crude inventory is recorded under crude inventories and partner over/under lift imbalances. As per IFRS 3 Business Combinations, all identifiable assets acquired in an acquisition must be valued at their fair value. In this case, the crude inventory was valued at the price achieved during the April lifting, which was US$86.28 per barrel (refer to Note 8, Acquisition of Interest in CWLH Joint Operation).

 

Adjusted unit operating cost per boe was US$31.72/bbl (H1 2023: US$40.27/bbl) (see Non-IFRS Measures section below in this document). The decrease is predominately due to increased production and a stable production cost.

 

 

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

 

Depletion charges for oil and gas properties increased by 73.4% to US$30.0 million in H1 2024, compared to US$17.3 million in H1 2023. This increase was primarily due to a 37% rise in production during H1 2024, higher unit rates driven by an increase in Asset Retirement Obligations (ARO), and the commencement of production from the PM323 infill wells. The depletion cost on a unit basis in H1 2024 was US$13.02/boe, a decrease of 1.0% compared to US$13.15/boe in H1 2023.

 

Depreciation of the Group's right-of-use assets and plant and equipment increased to US$8.2 million in H1 2024 from US$7.3 million in H1 2023, mainly due to lease changes and renewals.

 

 

Other expenses

 

Other expenses increased US$5.9 million during H1 2024 to US$14.3 million (H1 2023: US$8.4 million) predominately related to the recognition of a provision for two Lemang contingent payments with a combined fair value of US$5.5 million associated with the average brent price and average Saudi CP¹ exceeding US$80/bbl and USD620/MT respectively in first year of production. These two events were not recognised H1 2023 as at the time, future prices were not anticipated to exceed these forecasted prices (full details of the contingent payments were detailed in the Annual Report Note 37 Provisions).

 

 

Finance costs

 

Finance costs in H1 2024 were US$19.5 million (H1 2023: US$22.5 million), a decrease of US$3.0 million, predominately due to:

 

·      A warrant reserve was established during the 2023 equity raise, resulting in a US$6.1 million charge in that period. No corresponding charge was recorded in H1 2024.

·      Lending fees decreased US$1.8 million to US$0.4 million in H1 2024, from US$2.2 million in H1 2023. This decrease primarily resulted from one-off, non-recurring fees associated with the equity raise and working capital facility in the previous period.

 

 

 

¹The term "Saudi CP" typically refers to the Saudi Contract Price (CP), which is a benchmark price for liquefied petroleum gas (LPG) in the global market.

 

·      The RBL accretion fees and interest expenses increased by US$3.0 million to US$5.5 million in H1 2024, up from US$2.5 million in H1 2023. This increase reflects higher borrowings and a full six months of expenses in H1 2024, compared to the partial period of expense incurred in H1 2023, after entering into the RBL in May 2023.

·      ARO accretion expense increased by US$0.9 million to US$10.5 million in H1 2024, up from US$9.6 million in H1 2023. This increase in Asset Retirement Obligation (ARO) was primarily driven by two factors: the acquisition of additional CWLH ownership share in February 2024, and the increased percentage of completion for Lemang's EPCI project.

 

 

Other financial gains

 

Other financial gains in H1 2024 amounted to US$1.0 million (H1 2023: US$ nil), resulting from the revaluation of the warrant liability created during the 2023 equity raise. The warrant liability, recorded under Current Liabilities, is revalued at each reporting date. This gain reflects a reduction in the liability from US$3.5 million at year-end 2023 to US$2.5 million in H1 2024.

 

 

Taxation

 

The tax expense of US$2.0 million in H1 2024 (H1 2023: tax credit of US$10.3 million) comprised current tax charge of US$7.5 million (H1 2023: tax credit US$2.1 million) and a deferred tax credit of US$5.5 million (H1 2023: tax credit of US$8.2 million).

 

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

 

		H1 2024 USD'000		H1 2023 USD'000
Loss before tax		(29,129)		(70,275)
Tax calculated at the domestic rates appliable to the profit/loss in the respective countries (Australia 30%, Malaysia 38% and 24% and Singapore 17%)		(4,646)		(18,100)
Less the effects of:
Australian Petroleum Resource Rent Tax (PRRT) credit		(5,741)		(231)	(
Deferred PRRT tax expense		545		-
Non-deductible expenses		1,787		5,191
Deferred tax assets not recognised		7,856		4,977
Other income not subjected to tax		(482)		-
Adjustments to prior year		2,671		(2,178)
Tax expense/(credit) for the period		1,990		(10,341)

 

 

 

 

RECONCILIATION OF CASH

 

US 000	H1 2024		H1 2023 Reclassified1
Cash and cash equivalent at the beginning of   period		153,404		123,329
Revenue	185,060		86,660
Other operating income2	3,525		3,324
Production costs	(136,324)		(90,650)
Administrative staff costs2	(15,541)		(15,080)
General and administrative expenses2	(8,774)		(8,433)
Operating cash flows before movements in   working capital		27,946		(24,179)
Movements in working capital1		(40,271)		(71,377)
Net tax paid		(16,486)		(4,755)
Purchases of intangible exploration assets, oil and   gas properties, and plant and equipment3		(27,151)		(23,439)
Cash paid for acquisition of Sinphuhorm Assets		-		(27,853)
Cash received for acquisition of additional interest   16.67% of CWLH Assets		5,236		-
Dividends received from associate		3,768		-
Interest received		410		1,466
Net proceeds from issuance of shares		-		51,070
Shares repurchased		-		(2,084)
Repayment of lease liabilities		(7,658)		(7,009)
Total drawdown from borrowings		43,000		161,000
Repayment of borrowings		-		(50,000)
Repayment of costs and interest of borrowings		(8,394)		(793)
Other financing activities		(2,935)		(6,594)
Total cash and cash equivalent at the end of   period		130,869		118,782

 

 

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.

 

 

 

 

¹ Certain H1 2023 comparative information has been reclassified. The placement of decommissioning trust fund for the CWLH Assets are now reclassified from investing activities to working capital in accordance with the nature of activities.

² Other operating income, administrative staff costs and general and administrative expenses adjusted figures are non-IFRS measures.

³ Total capital expenditure was US$47.6 million (H1 2023: US$23.8 million), comprising total capital expenditure paid of US$27.1 million (H1 2023: US$23.4 million), accrued capital expenditure of US$16.2 million (H1 2022: US$0.4 million) and capitalisation of borrowing costs of US$4.3 million (H1 2023: nil).

 

 

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. 

 

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 leasing of 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.

 

 

 

USD'000 except where indicated		Six months ended 30 June 2024		Six months ended 30 June 2023		Twelve months ended 31 December 2023
Production costs (reported)		136,324		90,650		232,772
Adjustments
Lease payments related to operating activities1		8,764		7,493		16,155
Underlift, overlift and crude inventories   movement2		(19,972)		24,897		9,297
Workover costs3		(10,633)		(9,531)		(17,562)
Other income4		(3,200)		(2,584)		(6,375)
Non-recurring operational costs5		(6,775)		(11,565)		(19,654)
Non-recurring repair and maintenance6		(5,343)		(312)		(1,773)
Transportation costs7		(3,656)		(3,035)		(7,502)
PenMal Assets supplementary payments and   Australian royalties8		(6,324)		(7,298)		(16,056)
PenMal PNLP assets operational costs9		(994)		(6,670)		(19,273)
Adjusted production costs		88,191		82,045		170,029
Total production (barrels of oil equivalent)		2,780,677		2,037,420		4,566,060
Adjusted unit operating costs per barrel of oil   equivalent		31.72		40.27		37.24

                                                                                                                                                                                         

 

¹ 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.

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

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

⁴ Other income represents the rental income from a helicopter rental contract (a right-of-use asset) to a third party.

⁵ Non-recurring operational costs in H1 2024 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.

⁶ Non-recurring repair and maintenance costs in H1 2024 predominately related to floating hose repair at Montara, CALM buoy coating remediation and maintenance pigging of export flowline at Stag, and rectification costs of the cranes and platforms of PNLP asset at PenMal. The costs during H1 2023 predominately related to the repair of a gas turbine generator at the PenMal Assets PM329 PSC.

⁷ Transportation costs includes the pipeline tariff at PenMal and tanker costs at Stag and Montara associated with lifting costs.

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 Similar to H1 2023, PenMal non-operated assets operational costs in H1 2024 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.

 

 

 

 

 

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 follows:

 

USD'000	Six months ended 30 June 2024		Six months ended 30 June 2023		Twelve months ended 31 December 2023
Revenue	185,060		86,660		309,200
Production costs	(136,324)		(90,650)		(232,772)
Administrative staff costs	(15,757)		(15,538)		(30,197)
Other expenses	(14,312)		(8,446)		(22,841)
Share of results of associate	2,124		-		2,640
Other income, excluding interest income	3,528		3,324		14,404
Other financial gains	1,001		-		-
Unadjusted EBITDAX	25,320		(24,650)		40,434
Non-recurring
Net loss from oil price and foreign exchange   derivatives	15,425		-		10,395
Non-recurring opex1	13,112		18,547		40,700
Assets written off	38		-		3,067
Change in provision - Lemang PSC contingent   payments	5,500		-		(7,653)
Others2	820		2,976		3,704
	34,895		21,523		50,213
Adjusted EBITDAX	60,215		(3,127)		90,647

 

 

¹ Non-recurring opex mainly represents Montara interim tanker storage costs which was temporarily employed as a result of the repair work relating to the storage tanks of the FPSO. It also includes one-off repair and maintenance costs predominately related to CALM buoy coating remediation and maintenance pigging of export flowline at Stag, and rectification costs of the cranes and platforms of AAKBNLP asset at PenMal. The H1 2023 non-recurring costs mainly consisted of 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.  

² Includes business development related expenses, external funding sourcing costs, internal reorganisation costs and fair value loss on contingent consideration.

 

 

 

 

 

 

 

 

 

Net (debt)/cash

 

Net (debt)/cash 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 2024		30 June 2023		31 December 2023
Borrowings (principal sum)		(200,000)		(111,000)		(157,000)
Cash and cash equivalents		130,869		118,782		153,404
Net (debt)/cash		(69,131)		7,782		(3,596)

 

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

 

 

 

 

 

2024 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 2024 remain unchanged from the risks disclosed in the 2023 Annual Report pages 31 to 34.  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 balance sheet 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. Details of going concern are disclosed in Note 2.

 

 

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                                                       

17 September 2024                                                                           

 

 

 

 

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 2024

 

		Six months ended 30 June 2024		Six months ended 30 June  2023		Twelve months ended 31 December 2023
		Unaudited		Unaudited		Audited
	Notes	USD'000		USD'000		USD'000
Consolidated statement of profit or loss
Revenue		185,060		86,660		309,200
Production costs	4	(136,324)		(90,650)		(232,772)
Depletion, depreciation and amortisation	4	(38,180)		(24,574)		(76,141)
Administrative staff costs		(15,757)		(15,538)		(30,197)
Other expenses	4	(14,312)		(8,446)		(22,841)
Impairment of oil and gas properties		-		-		(29,681)
Share of results of associate	11	2,124		-		2,640
Other income		6,779		4,790		18,855
Finance costs	5	(19,520)		(22,517)		(41,829)
Other financial gains		1,001		-		-
Loss before tax		(29,129)		(70,275)		(102,766)
Income tax (expense)/credit	6	(1,990)		10,341		11,492
Loss for the period/year		(31,119)		(59,934)		(91,274)
Loss per ordinary share
Basic and diluted (US$)	7	(0.06)		(0.13)		(0.18)
Other comprehensive loss
Loss for the period/year		(31,119)		(59,934)		(91,274)
Items that may be reclassified subsequently   to profit or loss:
Loss on unrealised cash flow hedges		(34,440)		(10,985)		(30,509)
Hedging loss reclassified to profit or loss		15,425		-		10,322
		(19,015)		(10,985)		(20,187)
Tax credit relating to components of other   comprehensive loss		5,704		2,160		6,056
Other comprehensive loss		(13,311)		(8,825)		(14,131)
Total comprehensive loss for the      period/year		(44,430)		(68,759)		(105,405)

 

 

 

 

 

 

 

 

 

 

 

Condensed Consolidated Statement of Financial Position as at 30 June 2024

 

		30 June 2024		30 June 2023		31 December 2023
		Unaudited		Unaudited		Audited
				Restated*
	Notes	USD'000		USD'000		USD'000
Assets
Non-current assets
Intangible exploration assets	9	80,440		78,730		79,564
Oil and gas properties	10	480,189		429,548		457,202
Plant and equipment	10	10,508		7,329		10,462
Right-of-use assets	10	22,462		37,980		31,099
Investment in associate	11	25,007		27,853		26,651
Other receivables and prepayment	12	262,493		191,127		141,860
Deferred tax assets		45,678		16,688		26,774
Cash and cash equivalents	13	1,356		1,000		1,008
Total non-current assets		928,133		790,255		774,620
Current assets
Inventories		56,243		47,818		33,654
Trade and other receivables	12	33,354		72,716		124,379
Tax recoverable		4,801		8,496		4,085
Cash and cash equivalents	13	129,513		117,782		152,396
Total current assets		223,911		246,812		314,514
Total assets		1,152,044		1,037,067		1,089,134
Equity and liabilities
Equity
Capital and reserves
Share capital	14	456		456		456
Share premium account	14	51,827		51,827		51,827
Merger reserve	15	146,270		146,270		146,270
Share based payments reserve		27,889		27,365		27,673
Capital redemption reserve	16	24		24		24
Hedging reserve	17	(27,442)		(8,825)		(14,131)
Accumulated losses		(189,468)		(127,009)		(158,349)
Total equity		9,556		90,108		53,770
*Certain H1 2023 comparative information has been restated.  Please refer to Note 26.
		30 June 2024		30 June 2023		31 December 2023
		Unaudited		Unaudited		Audited
				Restated*
	Notes	USD'000		USD'000		USD'000
Non-current liabilities
Provisions	18	682,915		581,625		503,170
Borrowings	19	169,135		82,194		147,313
Lease liabilities		10,353		24,818		18,746
Other payable	20	17,337		29,014		16,966
Derivative financial instruments	21	5,897		6,386		6,708
Deferred tax liabilities		71,556		73,628		65,829
Total non-current liabilities		957,193		797,665		758,732
Current liabilities
Borrowings	19	29,829		22,802		7,260
Lease liabilities		14,192		14,107		14,118
Trade and other payables	20	88,381		73,752		113,979
Derivative financial instruments	21	35,762		4,599		17,977
Warrants liability	22	2,541		6,147		3,469
Provisions	18	11,994		16,941		108,525
Tax liabilities		2,596		10,946		11,304
Total current liabilities		185,295		149,294		276,632
Total liabilities		1,142,488		946,959		1,035,364
Total equity and liabilities		1,152,044		1,037,067		1,089,134

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

*Certain H1 2023 comparative information has been restated.  Please refer to Note 26.