JADESTONE ENERGY PLC

Earnings Release • Sep 20, 2022

National Storage Mechanism | Additional information RNS Number : 9499Z Jadestone Energy PLC 20 September 2022 Jadestone Energy 2022 Half Year Results and Interim Dividend Declaration 20 September 2022-Singapore: Jadestone Energy plc (AIM:JSE) ("Jadestone" or the "Company"), an independent oil and gas production company and its subsidiaries (the "Group"), focused on the Asia Pacific region, reports today its unaudited condensed consolidated interim financial statements, as at and for the six-month period ended 30 June 2022 (the "financial statements"). Management will host a conference call today at 9:00 a.m. UK time, details of which can be found in the release below. Paul Blakeley, President and CEO commented: "Jadestone delivered record financial results in the first half of 2022, with production increasing by c.50% compared to the first half of 2021, driven by a full period contribution from the Malaysian assets acquired in August 2021 and the impact of the Montara drilling programme in the second half of 2021, albeit offset by an unplanned shutdown at Montara early in 2022 due to a compressor engine failure. Revenues and adjusted EBITDAX increased by 63% and 113% respectively, due to the increase in production volumes and higher realised oil prices. As a result, we ended the period with a net cash balance of US$161.6 million, an increase of almost 40% compared to year-end 2021. Jadestone remains debt free. Despite all this, recent operational performance at Montara has been disappointing, especially given the substantial upgrade and repair work done to date. As previously announced, the field is currently shut-in as we progress a remediation plan for the Montara Venture FPSO following defects identified earlier this year. The plan involves emptying, cleaning, inspecting and, where necessary, resolving any defects in the tanks and hull of the FPSO. In particular, we are moving ahead with the permanent repair of 2C crude oil cargo tank and 4S ballast tank whilst prioritising entry and activity in other tanks in preparation for operational readiness. As we focus on safety and integrity, this activity will continue until we can ensure a safe and reliable restart of the FPSO. In parallel, we are making good progress in the appointment of, and work scope for, the independent reviewer, who will work with us to provide final assurance to Jadestone and the regulator on our remediation plans and operational readiness prior to the restart of production operations. While we understand that the lack of a firm restart date is frustrating for many of our stakeholders, our focus is on the remediation plan and its successful execution which, in turn, will restore confidence in the significant remaining value we see at Montara. We have also initiated a fundamental review of our hull and tank inspection and repair regime, which will include our maintenance approach, operating systems and organisational structure. As a near-term action to assist management, Jadestone's Board of Directors has established a special subcommittee, which will work closely with Company's executive and senior operations leadership, providing both additional support and challenge, while the Montara FPSO hull and tank remediation work is in progress. This will include weekly progress updates and reports. The balance sheet strength we have built in recent years, and the confidence in our existing asset portfolio and its planned growth, means we are well-positioned to weather the Montara shut-in without any anticipated impact on our investment programmes, inorganic growth, or near-term shareholder returns. We expect capital expenditures for the year to be in line with guidance of US$90.0 - 105.0 million. We have also taken the decision to increase the interim dividend by 10% to US$3.0 million and, subject to market conditions, we intend to complete the US$25.0 million share buyback programme launched in August and which has so far returned an incremental US$4.9 million to shareholders. The next phase of the shareholder returns strategy announced in June will be determined by the timing of production restart at Montara, our portfolio's operational performance, realised oil prices, and the timing and scale of incremental inorganic growth opportunities. The Company continues to deliver on its growth strategy. In June, we took a final investment decision on the Akatara gas development on the Lemang PSC in Indonesia, with activity at the site now well underway. Separately, the acquisition of the outstanding 10% stake in the Lemang PSC is expected to complete soon. In July, we announced the acquisition of a non-operated interest in the producing Northwest Shelf ("NWS") oil project offshore Australia, and are making good progress towards closing this transaction in Q4 2022. Our strong balance sheet underlines the success of our business model, supporting our planned investments for growth, and while the recent Montara asset incident is unfortunate, we are determined to fix it and deliver the original value proposition vindicating our strategy in the Asia Pacific region." Paul Blakeley EXECUTIVE DIRECTOR, PRESIDENT AND CHIEF EXECUTIVE OFFICER 2022 FIRST HALF RESULTS SUMMARY USD'000 except where indicated H1 2022 H1 2021 FY 2021 Production, boe/day 15,008 9,934 12,545 Realised oil price per barrel of oil equivalent (US$/boe)1 109.52 67.70 74.34 Realised gas price per million standard cubic feet (US$/mmscf) 2.03 - 1.61 Revenue 225,639 138,158 340,194 Operating costs per barrel of oil equivalent (US$/boe)2 25.71 28.16 26.22 Adjusted EBITDAX2 138,608 65,179 157,948 Profit/(Loss) after tax 49,486 2,495 (13,742) Earnings/(Loss) per ordinary share: basic (US$) 0.11 0.01 (0.03) Earnings/(Loss) per ordinary share: diluted (US$) 0.10 0.01 (0.03) Dividend per ordinary share (US��)3 0.65 0.59 1.93 Operating cash flows before movement in working capital 126,481 54,376 96,622 Capital expenditure 13,621 16,221 55,996 Net cash2 161,628 48,291 117,865 Operational and financial summary l Production increased 51% during H1 2022 to 15,008 bbls/d (H1 2021: 9,934 bbl/d). Production benefitted from a full period of the PenMal Assets acquired in August 2021 and the Montara activity programme in H2 2021, offset by unscheduled downtime at Montara early in 2022, a planned maintenance shutdown at Stag in May, and the shut-in of the non-operated PenMal Assets in February 2022 due to FPSO class suspension; l Average realised oil price1 in H1 2022 was US$109.52/bbl, 62% higher than H1 2021. The realised price includes a weighted average premium across the assets of US$6.99/bbl (H1 2021: US$3.12/bbl); l Revenue of US$225.6 million in H1 2022, up 63% from H1 2021 at US$138.2 million, due to higher production and higher average realised prices; l Closing crude stocks as at 30 June 2022 totalled 417,216 bbls, which were subsequently sold in the second half of 2022, generating provisional receipts of US$45.3 million, from a provisional weighted average realised price of US$108.97/bbl; l As at 30 June 2022, there was an underlift production entitlement carried forward of 130,359 bbls at the PenMal Assets, resulting in a receivable of US$16.8 million, calculated based on the average June 2022 Dated Brent price plus latest realised premium; l Unit operating costs4 of US$25.71/boe, down 9% from US$28.16/bbl in H1 2021 due to inclusion of the PenMal Assets, which have a lower opex/boe compared to the Australian producing assets; l Adjusted EBITDAX improved 113% to US$138.6 million compared to US$65.2 million in H1 2021, predominately due to increased production, higher oil prices and lower one-off project expenditures in Other Expenses; l Net profit after tax in H1 2022 of US$49.5 million compared to US$2.5 million in H1 2021; l Operating cash flows before movements in working capital in H1 2022 of US$126.5 million, up 133% compared to H1 2021; l Capital expenditure in H1 2022 of US$13.6 million, down 16% compared to H1 2021 due to the phasing of expenditure in H2 2022; l Cash balances of US$161.6 million as at 30 June 2022 (H1 2021: US$48.3 million), with no debt outstanding; and l Recommended interim dividend for FY2022 of US��0.65/share3 (H1 2021: US��0.59/share), equivalent to a total distribution of US$3.0 million (H1 2021: US$2.8 million). On 2 August 2022, the Company announced the launch of a share buyback programme with a maximum amount of US$25.0 million. As at 16 September 2022, 4.7 million of shares had been acquired at an accumulated cost of US$4.9 million. Business development l On 16 November 2019, the Group executed a sale and purchase agreement with OMV New Zealand Limited ("OMV"), to acquire an operated 69% interest in the Maari project, subject to customary conditions, including government approvals. Following legislative changes to New Zealand's upstream regulatory framework at the end of 2021, Jadestone has continually engaged with OMV and the New Zealand Government to seek clarity on the processes, terms and associated timeline required to complete the Maari transaction. Despite these efforts, it remains unclear under what circumstances and in what timeframe completion of the transaction and transfer of operatorship can occur; l On 6 June 2022, the Group announced that a final investment decision had been taken on the Akatara gas field development onshore Indonesia, following the receipt of necessary consent from the Indonesian upstream regulator. The project is now in the development phase with first gas anticipated in the first half of 2024; l On 24 November 2021, the Group executed a settlement and transfer agreement with PT Hexindo Gemilang Jaya to acquire the remaining 10% interest in the Lemang PSC for US$0.5 million and a waiver of unpaid amounts related to the PSC. Indonesian government approval is anticipated in Q4 2022; and l On 28 July 2022, the Group announced the execution of a sale and purchase agreement with BP Developments Australia Pty Ltd ("BP") to acquire BP's non-operated 16.67% working interest in the Cossack, Wanaea, Lambert and Hermes oil fields development offshore Western Australia, for a total initial headline cash consideration of US$20.0 million, and certain subsequent contingent and decommissioning security payments. Significant events l On 7 February 2022, the Bunga Kertas FPSO, deployed at the non-operated PenMal Assets, had its class suspended, resulting in the non-operated PenMal Assets being shut-in and production suspended. Production is expected to remain shut-in for the remainder of 2022. The estimated adjustment to the production guidance provided in August 2022 to arrive at the current production guidance for full year 2022 is a reduction of c.720 boe/d; l As previously announced, on 17 June 2022, between three to five cubic metres of crude oil was released to sea during a routine oil transfer between tanks on the Montara Venture FPSO. The facility was immediately shut-in as a precaution and the relevant authorities notified. Following a temporary repair and isolation of the 2C cargo tank where the leak originated, production was restarted on 4 July 2022 while a permanent repair was being developed; l On 12 August 2022, an additional defect was identified in a ballast water tank on the Montara Venture FPSO during preparation work for a permanent repair to the 2C cargo tank. The Group took the decision to temporarily shut-in production at Montara to prioritise the permanent repairs, removing a number of production operations personnel in order to provide accommodation for additional inspection and repair crews due to an inability to simultaneously accommodate both; and l On 15 September 2022, Jadestone's Board of Directors established a temporary special sub-committee to assist management during the ongoing Montara FPSO hull and tank workstreams. It will receive weekly progress reports on the Montara FPSO remediation activities, and interact directly with the Group's senior operations leadership to review actions and progress towards the remediation plan's objectives, including the restart of production. 2022 Guidance l Production: 11,000 - 13,000 boe/d (as announced on 12 September 2022, the production forecast was decreased due to the shut-in of production from the Montara fields); l Unit opex: US$31.00 - 37.00/boe (increased from previous guidance at US$23.00 - US$28.00 primarily due to incorporating the lower production forecast above) ; and l Capex: US$90.0 - 105.0 million (unchanged). 1 Realised oil price represents the actual selling price inclusive of premiums. 2 Operating costs per boe, adjusted EBITDAX and net cash are non-IFRS measures and are explained in further detail below. 3 Dividend per ordinary share calculated based on outstanding number of shares at period/year end. The actual dividend per share will reflect any changes in the shares outstanding between the period/year end and the associated record date including the shares buyback. 4 Unit operating costs per boe before workovers and movement in inventories but including net lease payments and certain other adjustments (see non-IFRS measures below). Enquiries Jadestone Energy plc. Paul Blakeley, President and CEO +65 6324 0359 (Singapore) Bert-Jaap Dijkstra, CFO Phil Corbett, Investor Relations Manager +44 7713 687 467 (UK) ir@jadestone-energy.com Stifel Nicolaus Europe Limited (Nomad, Joint Broker) +44 (0) 20 7710 7600 (UK) Callum Stewart / Jason Grossman / Ashton Clanfield Jefferies International Limited (Joint Broker) +44 (0) 20 7029 8000 (UK) Tony White / Will Soutar Camarco (Public Relations Advisor) +44 (0) 203 757 4980 (UK) Billy Clegg / Georgia Edmonds / James Crothers jadestone@camarco.co.uk Conference call and webcast The management team will host an investor and analyst conference call at 9:00 a.m. (London)/4:00 p.m. (Singapore) today, Tuesday, 20 September 2022, including a question-and-answer session. The live webcast of the presentation will be available at the below webcast link. Dial-in details are provided below. Please register approximately 15 minutes prior to the start of the call. The results for the financial period ended 30 June 2022 will be available on the Company's website at: www.jadestone-energy.com/investor-relations/ Webcast link: https://app.webinar.net/VXGleQG4RWA Event title: Jadestone Energy plc first-half 2022 results Time: 9:00 a.m. (UK time) / 4:00 p.m. (Singapore time) Date: Tuesday, 20 September 2022 Conference ID: 65496332 Dial-in number details: Country Dial-In Numbers United Kingdom 08006522435 Australia 1800076068 Canada (Toll free) 888-390-0546 France 0800916834 Germany 08007240293 Hong Kong 800962712 Indonesia 0078030208221 Japan 006633812569 Malaysia 1800817426 Netherlands 08000227908 New Zealand 0800453421 Singapore 8001013217 Spain 900834776 Sweden 0200899189 Switzerland 0800312635 United States (Toll free) 888-390-0546 DIVIDEND DECLARATION AND PROGRESS SHARE BUYBACK PROGRAMME On 20 September 2022, the Directors declared a 2022 interim dividend of 0.65 US cents/share, equivalent to a total distribution of US$3.0 million. The timetable for the dividend payment is as follows: l Ex-dividend date: 29 September 2022 l Record date: 30 September 2022 l Payment date: 14 October 2022 The Group's growth-orientated strategy remains unchanged, with the objective of establishing a leading Asia-Pacific upstream company through acquiring and maximising the value of producing fields and development assets. The Group prioritises organic reinvestment, and maintains a conservative capital structure in order to capitalise on inorganic growth opportunities as they arise. Notwithstanding this, the Group believes that its production and development led business model is fundamentally pre-disposed to provide meaningful shareholder returns, particularly during times of higher oil prices. The Company targets a sustainable base dividend, with a targeted split one-third to an interim dividend and two-thirds to a final dividend, growing over time in line with underlying cash flow generation. The base dividend may be augmented over time by additional shareholder returns (in the form of share buybacks, special dividends and/or tender offers) if deemed appropriate by the Company. The Company does not offer a dividend reinvestment plan and does not offer dividends in the form of ordinary shares. On 2 August 2022, the Company announced the launch of a share buyback programme (the "Programme") in accordance with the authority granted by the shareholders at the Company's annual general meeting on 30 June 2022. The maximum amount of the Programme is US$25.0 million, and the Programme will not exceed 46,574,528 ordinary shares. There is no certainty on the volume of shares that may be acquired, nor any certainty on the pace and quantum of acquisitions. As at 16 September 2022, the Company had acquired 4.7 million shares at a weighted average cost of ��0.89 per share, resulting in an accumulated total of US$4.9 million. 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 whilst minimising the environmental footprint of its operations. 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 third Sustainability Report in June 2022, which covered the Group's ESG performance in 2021, as well as commitments to further improvements in 2022 across key focus areas. This section provides an overview of period-to-date performance of the Group, representing the Stag and Montara fields, the PenMal operated assets and, where relevant, the Akatara gas development. Net Zero and GHG emissions The Group committed 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 commitment as well as Jadestone's strategy through the energy transition can be viewed on Jadestone's website1. A key element of the Net Zero commitment is the development of an emissions reduction roadmap for Jadestone's operated assets, which will inform the interim GHG reduction targets for the Group. Jadestone has engaged a reputable international consultant to support its Net Zero workstreams, which will be progressed throughout H2 2022 and into 2023. The Group is on track to publish its Net Zero roadmap in 2023 and is committed to being transparent in the implementation of the roadmap on at least an annual basis. Illustrative of its efforts to minimise GHG emissions, a solar photovoltaic installation was piloted at the Akatara gas field development in Indonesia in April 2022, replacing diesel generators at four well pads. Solar power now fully meets well pad lighting and electricity needs, with potentially broader application within the Akatara development, such as use in the accommodation camp. In collaboration with other operators in the area, Jadestone is participating in the planting of over 27,000 mangrove trees to positively impact the health and wellness of local communities and environment. 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. At the operated PenMal Assets, there have been no recordable incidents since Jadestone assumed operatorship in August 2021. Similarly, since construction started at the Akatara gas development in Indonesia earlier this year, no recordable incidents have occurred. In Australia, there were three recordable incidents with one at Stag classified as a Lost Time Injury ("LTI"). The crew member concerned suffered a minor injury, recovered quickly and is back to work. The LTI was managed in accordance with Jadestone's Injury & Illness Management Procedure, with a detailed investigation completed and ensuing actions and engineering modifications fully implemented. 1 https://www.jadestone-energy.com/jadestone-announces-2040-net-zero-target/ As referenced previously, in June 2022, between three to five cubic metres of crude oil was released to sea during a routine oil transfer between tanks on the Montara Venture FPSO. Production operations resumed on 4 July 2022 but were then shut-in again in August 2022 after an additional internal defect was identified in a ballast water tank on the FPSO. The Group took the decision to temporarily shut-in production at Montara to prioritise permanent repairs, removing a number of production operations personnel in order to provide accommodation for additional inspection and repair crews due to an inability to simultaneously accommodate both. Governance On 7 April 2022, the Group announced the immediate appointment of Jenifer Thien as an independent non-executive director. Jenifer brings knowledge and experience in environmental, social and governance ("ESG") strategy. Jenifer joined the Remuneration, Governance and Nomination, and Health, Safety, Environment and Climate (HSEC) committees. On 29 April 2022, Daniel Young stepped down from his role as the Chief Financial Officer ("CFO") and Executive Director and left the Group. Michael Horn took the role of interim CFO until 22 August 2022, when Bert-Jaap Dijkstra was appointed by the Board as CFO and Executive Director. Jadestone's Board of Directors (the "Board") supports management's decision to shut-in operations at Montara to focus on the inspection, maintenance and repair activities associated with the Montara FPSO hull and tanks, recognising the elevated requirements to restart operations as outlined within the General Direction issued by NOPSEMA on 12 September 2022. The Board has every confidence in the Group's abilities to execute the remediation plan efficiently and effectively and to the satisfaction of the regulatory authorities. During this period, a technical subcommittee of the Board will work more closely with senior management, providing both support and challenge, while the Montara FPSO hull and tank remediation plan is in progress. This will include weekly progress updates and reports. OPERATIONAL REVIEW Producing assets Australia Montara project The Montara project, in production licences AC/L7 and AC/L8, is located 254 km offshore Western Australia, in a water depth of approximately 77 metres. The Montara project comprises three separate fields being Montara, Skua and Swift/Swallow, which are produced through an owned FPSO, the Montara Venture. As at 31 December 2021, the Montara assets had proven plus probable reserves of 20.9mm barrels of oil, 100% net to Jadestone. The fields produce light sweet crude (42o API, 0.067% mass sulphur), which typically sells for average Dated Brent plus the average Tapis differential of the prior two months before the lifting date. This premium ranged from US$3.53/bbl to US$6.19/bbl during H1 2022. Montara production averaged 7,509 bbls/d in H1 2022 (H1 2021: 7,269 bbls/d). The higher production was a result of the drilling of H6 and the subsea workovers of Skua 10 and 11 in the second half of 2021. The additional production was partially offset by an unplanned gas turbine replacement and a temporary loss of subsea communication impacting uptime from the Swallow-11 well during H1 2022. As previously announced, on 17 June 2022, between three to five cubic metres of crude oil was released to sea during a routine oil transfer between tanks on the Montara Venture FPSO. The facility was immediately shut-in as a precaution and the relevant authorities notified. Following a temporary repair and isolation of the 2C cargo tank where the leak originated, production was restarted on 4 July 2022 while a permanent repair was being developed. On 12 August 2022, an additional internal defect was identified in a ballast water tank on the Montara Venture FPSO during preparation work for a permanent repair to the 2C cargo tank. The Group took the decision to temporarily shut-in production at Montara to prioritise permanent repairs, removing a number of production operations personnel in order to provide accommodation for additional inspection and repair crews due to an inability to simultaneously accommodate both. There were three liftings during H1 2022, resulting in total sales of 1.3 mmbbls, compared to 1.5 mmbbls during H1 2021 from the same number of liftings. Stag oilfield The Stag oilfield, in production licence WA-15-L, is located 60 km offshore Western Australia in a water depth of approximately 47 metres. As at 31 December 2021, the field contained total proved plus probable reserves of 12.6mm barrels of oil, 100% net to Jadestone. The Stag oilfield produces heavier sweet crude (18o API, 0.14% mass sulphur), which historically sells at a premium to Dated Brent. The premium of the H1 2022 lifting was US$23.72/bbl compared to a weighted average of US$11.09/bbl in H1 2021, reflecting the increase in refinery demand for heavy oil with low sulphur content. Production during H1 2022 was 2,057 bbls/d, compared to 2,665 bbls/d during H1 2021, due to a scheduled maintenance shutdown in May 2022. The shutdown was to perform pressure vessel inspections and occurs once in every three years. Due to the lifting schedules, there was one lifting in H1 2022 for 0.3 mmbls compared to two in H1 2021 for 0.5mmbls. Malaysia Operated: PM 323 and PM 329 PSCs & Non-operated: PM 318 and AAKBNLP PSCs The PenMal Assets consist of four licences, two of which are operated by the Group. The two operated licences comprise a 70% interest in the PM329 PSC, containing the East Piatu field, and a 60% interest in the PM323 PSC, which contains the East Belumut, West Belumut and Chermingat fields. Both PSCs are located approximately 230km northeast of Terengganu in shallow water. The two non-operated ("OBO") licences consist of 50% working interests in each of the PM318 PSC and in the Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields (the "AAKBNLP") PSC. The two non-operated PSCs are located in the same region as PM329 and PM323. As at 31 December 2021, the PenMal Assets contained total proved plus probable reserves of 11.2mmboe, net to Jadestone. The PenMal Assets produce light sweet crude that is blended to Tapis grade (43o API, 0.04% mass sulphur). This premium ranged between US$0.96/bbl to US$6.76/bbl in H1 2022. During H1 2022, the average production from the PenMal Assets was 4,578 bbls/d of oil and 5,191 mscf/d of gas, creating a combined production of 5,443 boe/d, net to Jadestone's working interest. There was no comparable production in H1 2021 as the acquisition of the PenMal Assets was completed in August 2021. On 7 February 2022, the Bunga Kertas FPSO, deployed at the non-operated assets, had its class suspended, resulting in the fields having to shut-in and cease production. Since the class suspension, there has been no production and it is expected that production will remain shut-in for the remainder of 2022. Currently, following a subsequent safety incident, the operator has paused its FPSO repair plan and is assessing the full range of alternatives, which include a comprehensive programme of repairs, an asset divestment or, given that the OBO licenses expire in 2024, a move towards decommissioning the asset 12 months earlier than originally planned. There were seven oil liftings during H1 2022, for total sales of 0.5 mmbbls in addition to the sale of 939.7 mmscf of gas. Pre-production assets Indonesia Lemang PSC The Lemang PSC (Jadestone 90% working interest) is located onshore Sumatra, Indonesia. The PSC contains the Akatara field, which has been substantially de-risked with 11 wells drilled into the structure, plus three years of oil production history, up until the field ceased oil production in December 2019. Jadestone is redeveloping Akatara to supply gas, condensate and LPGs for local and regional use. The Akatara gas field has been independently estimated to contain a 2C gross resource (pre local government back-in rights) of 63.7 bcf of sales gas, 2.5 mmbbls of condensate and 5.6 mmboe of LPG, equating to a combined 18.7 mmboe of resource, or 16.8 mmboe net to Jadestone's existing 90% working interest. On 30 June 2021, the Minister of Mines and Energy of Indonesia issued a Ministerial decree that facilitates the development and commercialisation of the Akatara gas field, allocating gas sales from the gas field in the Lemang PSC to a subsidiary of PT Perusahaan Listrik Negara, the national electricity utility, and the associated production and sales of LPG to the local domestic market in Jambi province, together with condensate sales to a local buyer. On 1 December 2021, a gas sale agreement was signed between Jadestone and PT Pelayanan Listrik Nasional Batam, as buyer. On 24 November 2021, the Group announced the acquisition of the remaining 10% interest in the PSC from PT Hexindo Gemilang Jaya ("Hexindo"), subject to customary approvals. The transaction was approved by the shareholders of Hexindo's ultimate parent company, Eneco Energy Limited, on 20 June 2022 and the government approval, representing the last required approval for closing, is anticipated in Q4 2022. On 6 June 2022, the Group announced that a final investment decision had been taken on the Akatara field development following the necessary approvals by the Indonesian upstream regulator. The Group awarded the engineering, procurement, construction and installation contract on 3 June 2022 and development activities have commenced. Jadestone is pursuing a low-cost development for the field including efficient use of existing wells and infrastructure thereby minimising the incremental impact on the local environment. The Akatara gas project remains on track for first gas in the first half of 2024. Vietnam Block 51 and Block 46/07 PSCs Jadestone holds a 100% operated working interest in the Block 46/07 and Block 51 PSCs, both in shallow water in the Malay Basin, offshore southwest Vietnam. The two contiguous blocks hold three discoveries: the Nam Du gas field in Block 46/07 and the U Minh and Tho Chu gas/condensate fields in Block 51, with aggregate 2C resources of 93.9 mmboe. The Tho Chu discovery in Block 51 is currently under a suspended development area status, with the exploration period expiring in June 2023. Jadestone has, in recent months, been negotiating with the end-user of gas from its offshore discoveries. These discussions are still at an early stage, but support the prospect of meaningful progress towards commercialising the significant and strategic resource in Jadestone's licences. Development of this resource would lessen Vietnam's future dependence on expensive imports of natural gas and contribute towards the country's stated goal of net zero greenhouse gas emission by 2050. Pending acquisition Australia North West Shelf Project On 28 July 2022, the Group executed a sale and purchase agreement with BP Developments Australia Pty Ltd to acquire BP's non-operated 16.67% working interest in the Cossack, Wanaea, Lambert and Hermes oil field development (the "North West Shelf Project"), offshore Australia for a total initial headline cash consideration of US$20.0 million, and certain subsequent contingent and decommissioning payments. The economic effective date of the acquisition is 1 January 2020, meaning that the Group will receive all economic benefits since that date. The Group estimates that the final closing adjustment will be higher than the initial cash consideration of US$20.0 million, in effect representing a net cash income to Jadestone. Upon closing, the Group will pay US$41 million in cash, representing the first of three instalments to be made relating to the decommissioning trust fund payment. The two final instalments of the decommissioning trust fund payment will be completed through two equal cash contributions of US$20.5 million which are payable around or before 31 December 2022 and 2023, respectively. The completion of the acquisition is subject to customary closing conditions, including various regulatory approvals. The Group anticipates completion of the transaction in Q4 2022. New Zealand Maari project On 16 November 2019, the Group executed a sale and purchase agreement with OMV New Zealand Limited ("OMV"), to acquire an operated 69% interest in the Maari project, located 120 km offshore New Zealand, subject to customary closing adjustments. The transaction has achieved several key milestones with regard to regulatory approvals. Following legislative changes to New Zealand's upstream regulatory framework at the end of 2021, Jadestone has continually engaged with OMV and the New Zealand Government to seek clarity on the processes, terms and associated timeline required to complete the Maari transaction. Despite these efforts, it remains unclear under what circumstances and in what timeframe completion of the transaction and transfer of operatorship can occur. FINANCIAL REVIEW The following table provides selected financial information of the Group, which was derived from, and should be read in conjunction with, the unaudited condensed consolidated interim financial statements for the period ended 30 June 2022. USD'000 except where indicated Six months ended 30 June 2022 Six months ended 30 June 2021 Twelve months ended 31 December 2021 Sales volume, barrels of oil equivalent (boe) 2,199,583 2,040,792 4,664,297 Production, boe/d 15,008 9,934 12,545 Realised oil price per barrel of oil equivalent, US$/boe1 109.52 67.70 74.34 Realised gas price per million standard cubic feet, US$/mmscf 2.03 - 1.61 Revenue 225,639 138,158 340,194 Production costs (83,401) (62,492) (206,523) Operating costs per barrel of oil equivalent (US$/boe)2 25.71 28.16 26.22 Adjusted EBITDAX2 138,608 65,179 157,948 Unit depletion, depreciation & amortisation (US$/boe) 12.06 15.70 13.67 Profit before tax 87,253 11,148 1,080 Profit /(Loss) after tax 49,486 2,495 (13,742) Earnings/(Loss) per ordinary share: basic (US$) 0.11 0.01 (0.03) Earnings/(Loss) per ordinary share: diluted (US$) 0.10 0.01 (0.03) Dividend per ordinary share (US��)3 0.65 0.59 1.93 Operating cash flows before movement in working capital 126,481 54,376 96,622 Capital expenditure 13,621 16,221 55,996 Net cash2 161,628 48,291 117,865 Benchmark commodity price and realised price The actual average realised oil price in H1 2022 increased by 62% to US$109.52/bbl, compared to US$67.70/bbl during H1 2021. The average benchmark oil price incorporated into the Group's liftings was US$102.53/bbl during H1 2022, an increase of 59% compared to H1 2021 at US$64.58/bbl. The average premium for the period was US$6.99/bbl, compared to H1 2021 of US$3.12/bbl. The increase reflected the demand for Stag crude which obtained a premium of US$23.72/bbl (H1 2021: US$11.09/bbl) and increases in Tapis linked crude with Montara and the PenMal Assets at US$4.52/bbl (H1 2021: US$1.14/bbl) and US$3.86/bbl (H1 2021: nil), respectively. 1 Realised oil price represents the actual selling price inclusive of premiums. 2 Operating cost per boe, adjusted EBITDAX and net cash are non-IFRS measures and are explained below. 3 Dividend per ordinary share calculated based on outstanding number of shares at period/year end. The actual dividend per share will reflect any changes in the shares outstanding between the period/year end and the associated record date including the shares buyback. Production and liftings The Group generated average production of 15,008 boe/d in H1 2022, compared to 9,934 bbls/d in H1 2021. Production increased due to the acquisition of the PenMal Assets in August 2021, which generated additional production of 5,443 boe/d during H1 2022. Montara increased to 7,509 bbl/d from 7,269 bbl/d in H1 2022 due to the completion of the drilling of H6 and the subsea workovers of Skua 10 and 11 at the end 2021 offset by operational issues in H1 2022, in particular downtime associated with changing out the gas compressor engine on the FPSO. Stag production decreased in H1 2022 to 2,057 bbl/d (H1 2021: 2,665 bbl/d) due to a planned shutdown for vessel inspections and natural field decline. The Group had 11 liftings during the period (H1 2021: five), resulting in sales of 2.0 mmbbls (H1 2021: 2.0 mmbbls). The PenMal Assets contributed seven oil liftings in H1 2022, representing 0.5 mmbbls. In addition, the PenMal Assets produced and sold 939.7 mmscf (approximately 0.2 mmboe) of natural gas. Lifted volumes were lower than the comparable period last year at Montara and Stag due to the phasing of liftings (four in H1 2022 compared to five in H1 2021). The Australian closing crude inventories of 417,216 bbls were valued at cost of US$25.9 million, which were subsequently sold in the second half of 2022, generating provisional receipts of US$45.3 million, from a provisional weighted average realised price of US$108.97/bbl. PenMal Assets were in an underlift carried forward position of 130,359 bbls, reflecting a market value of US$16.8 million, calculated based on the average June 2022 Dated Brent price plus latest realised premium. Revenue The Group generated US$225.6 million of revenue in H1 2022, compared to US$138.2 million for the same period in 2021, an increase of 63%. The increase of US$87.4 million is due to: �� The PenMal Assets generating US$48.3 million of crude oil revenue (H1 2021: nil) and US$1.9 million of gas revenue (H1 2021: nil) in H1 2022, following completion of the acquisition in August 2021; �� Higher average realised oil prices at Montara of US$106.76 bbl (H1 2021: US$66.66 bbl) and Stag at US$128.13 bbl (H1 2021: US$70.87 bbl) in H1 2022, contributing an additional US$68.0 million; partly offset by �� A lower lifted volume by 452,795 bbls at Montara and Stag, representing an estimated decrease of US$30.6 million between the comparable periods. Production costs Production costs in H1 2022 were US$83.4 million (H1 2021: US$62.5 million), an increase of US$20.9 million, predominately due to the acquisition of the PenMal Assets which contributed US$24.7 million, and a reduction of US$3.8 million at Montara and Stag. Production costs included: �� The PenMal Assets incurred US$16.7 million (H1 2021: nil) of Malaysian supplementary payments, due to the realised price exceeding the escalated base price incorporated into the PSC terms; �� Repair and maintenance ("R&M") costs of US$25.3 million, compared to US$12.1 million in H1 2021. The PenMal Assets incurred routine maintenance of US$2.7 million (H1 2021: nil), Stag an additional US$4.6 million on structural marine maintenance and import hose replacement and Montara an additional US$5.9 million predominately on Skua 11 well subsurface repairs; �� Operational costs at US$32.6 million, an increase of US$8.3 million compared to H1 2021, predominately associated with the PenMal Assets; �� Logistics costs increased by US$5.1 million, with the PenMal Assets incurring US$2.6 million (H1 2021: nil). Australia increased by US$2.5 million due to higher fuel costs for operating vessels and helicopters; �� Transportation costs of US$2.9 million (H1 2021: US$0.5 million), predominately associated with the PenMal Assets and Stag offtake arrangements; �� Workover costs reduced by US$1.6 million due to differences in the phasing of workovers; �� The PenMal Assets were in an underlift carried forward position of 130,359 bbls (H1 2021: nil) resulting in a production credit of US$9.9 million at the end of H1 2022; and �� Montara and Stag generated a credit net inventory movement of US$8.5 million, reflecting the increase in closing crude balances compared to the beginning of the period. Unit operating costs per boe were US$25.71 bbl (H1 2021: US$28.16/bbl) before workovers and movement in inventories but including lease payments and taking into account various other adjustments (see IFRS measures below). Depletion, depreciation and amortisation ("DD&A") The depletion charges of oil and gas properties were US$35.1 million in H1 2022, compared to US$39.7 million in H1 2021. The depletion cost on a unit basis was US$12.06/boe in H1 2022 (H1 2021: US$15.70/bbl), predominately due to the inclusion of the PenMal Assets at US$1.61/boe which benefitted from the low cost base following the acquisition, thus lowering the weighted average DD&A unit charge. Stag and Montara increased over the comparable period by US$2.63/bbl and US$1.71/bbl, respectively, reflecting the completion of development projects and natural decline of the production profile. Other expenses Other expenses represent the Group's general and administrative ("G&A") costs, one-off project costs and other miscellaneous expenditures. Total other expenses decreased by US$7.0 million in H1 2022 to US$5.5 million (H1 2021: US$12.5 million) due to lower G&A, one-off project costs and hedging losses incurred in H1 2021. Other income Other income was US$5.6 million in H1 2022, an increase of US$1.9 million (H1 2021: US$3.7 million). The increase was mainly due to a refund of interest paid to the Australian Taxation Office as part of an early repayment of outstanding 2019 tax amounts previously deferred under a COVID-19 arrangement. Taxation The tax charge of US$37.8 million in H1 2022 (H1 2021: US$8.7 million) was split between a current tax charge of US$34.9 million (H1 2021: US$8.9 million) and a deferred tax charge of US$2.8 million (H1 2021: credit of US$0.2 million). The current tax charge included US$29.2 million (H1 2021: US$11.4 million) of Australian corporate tax plus Malaysian Petroleum Income Tax ("PITA") tax of US$5.9 million (H1 2021: nil), offset by a net Australian Petroleum Resource Rent tax ("PRRT") credit of US$0.2 million (H1 2021: US$2.5 million). Australian PRRT Australian PRRT is a cash-based tax charged to petroleum operations at the rate of 40% and deductible from income tax. The current tax credit of US$0.2 million is associated with Stag operations, due to the utilisation of carried forward PRRT losses. Montara is not anticipated to incur PRRT expense in the future, as it has unutilised PRRT carried forward credits of US$3.4 billion (H1 2021: US$3.3 billion). Based on management's latest forecasts, the historical accumulated PRRT net losses will more than offset PRRT that would arise on future PRRT taxable profits. Malaysian PITA Malaysia PITA is imposed at the rate of 38% on income from petroleum operations in Malaysia, no other taxes are imposed on income from petroleum operations. Deferred tax The deferred tax movement during the period reflects timing differences for corporate tax, PITA and PRRT. The Group incurred a deferred tax charge of US$2.8 million in H1 2022 (H1 2021: credit of US$0.3 million), because of timing differences between the PITA tax and accounting treatment of the Malaysian crude under-lift position of US$3.6 million (H1 2021: nil) and a deferred tax credit in Australia of US$0.8 million from the timing differences of the accounting and tax bases of the oil and gas properties. H1 2022 RECONCILIATION OF CASH US$'000 US$'000 Total cash and cash equivalent, 31 December 2021 117,865 Revenue 225,639 Other operating income 3,524 Production costs (83,401) Administrative staff costs (14,482) General and administrative expenses (4,799) Operating cash flows before movements in working capital 126,481 Movements in working capital (22,658) Net tax paid (34,177) Interest paid (600) Purchases of intangible exploration assets, oil and gas properties, and plant and equipment1 (13,364) Other investing activities 170 Financing activities (12,089) Total cash and cash equivalent, 30 June 2022 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 operating cost per barrel of oil equivalent (opex/boe), adjusted EBITDAX and net cash. The following notes describe why the Group has selected these non-IFRS measures. 1 Total capital expenditure was US$13.6 million, comprising total capital expenditure paid of US$13.4 million, plus accrued capital expenditure of US$0.2 million. Operating costs per barrel of oil equivalent (Opex/boe) Opex/boe is a non-IFRS measure used to monitor the Group's operating cost efficiency, as it measures operating costs to extract hydrocarbons from the Group's producing reservoirs on a unit basis. Opex/boe is defined as total production costs excluding crude inventories movement, underlift/overlift, workovers (to facilitate better comparability period to period), non-recurring R&M, supplementary payments, DD&A, transportation, and short term COVID-19 incentives. It includes lease payments related to operational activities, net of any income earned from right-of-use assets involved in production. The adjusted production cost is divided by total produced barrels of oil equivalent for the prevailing period to determine the unit operating cost per boe. Six months ended Six months ended Twelve months ended USD'000 except where indicated 30 June 2022 30 June 2021 31 December 2021 Production costs (reported) 83,401 62,492 206,523 Adjustments Lease payments related to operating activities1 6,371 6,444 10,619 Underlift, overlift and crude inventories movement2 18,412 (5,642) (9,680) Workover costs3 (8,435) (10,027) (67,006) Other income4 (2,410) (2,286) (4,512) Non-recurring repair and maintenance5 (5,510) - (6,593) Australian transportation costs (510) (541) (1,231) PenMal Assets supplementary payments6 (16,731) - (8,255) Australian Government JobKeeper scheme - 196 196 PenMal non-operated assets FPSO rectification costs7 (4,748) - - Adjusted production costs 69,840 50,636 120,061 Total production (barrels of oil equivalent) 2,716,436 1,797,989 4,578,962 Operating costs per barrel of oil equivalent 25.71 28.16 26.22 1 Lease payments related to operating activities are payments considered to be operating costs in nature, including leased helicopters for transporting offshore crews. 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 repair and maintenance costs in H1 2022 related to the Montara Skua 11 well subsurface repairs and Stag structural marine maintenance and import hose replacement. The costs from the year ended 2021 related to the Montara Swift North SCM change out and facility integrity baseline survey. 6 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. 7 PenMal non-operated assets FPSO rectification costs refer to the costs incurred to repair the FPSO BUK CLASS at PM318 and AAKBNLP PSCs following its suspension 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 information to analyse cash generation and financial performance of the Group. Adjusted EBITDAX is defined as profit from continuing activities before income tax, finance costs, interest income, DD&A, other financial gains, non-recurring expenses and exploration assets write-offs. The calculation of adjusted EBITDAX is as follows: Six months ended Six months ended Twelve months ended USD'000 30 June 2022 30 June 2021 31 December 2021 Revenue 225,639 138,158 340,194 Production costs (83,401) (62,492) (206,523) Administrative staff costs (15,165) (12,067) (25,068) Other expenses (5,503) (12,501) (26,181) Other income, excluding interest income 3,528 3,643 7,602 Other financial gains - - 266 Unadjusted EBITDAX 125,098 54,741 90,290 Non-recurring Net loss from oil price derivatives - 4,633 4,633 Non-recurring opex1 13,135 1,574 53,096 Intangible exploration assets written off - - 5,260 Loss on contingent considerations - - 438 Other 375 4,231 4,231 13,510 10,438 67,658 Adjusted EBITDAX 138,608 65,179 157,948 1 Non-recurring opex represents one-off major maintenance/well intervention activities, in particular the Montara Skua 11 well subsurface repairs and Stag structural marine maintenance and import hose replacement. The H1 2021 non-recurring costs mainly consisted of workover campaigns at Skua 10 & 11, while Swift North SCM change out and facility integrity baseline survey were included in the 2021 full year costs. Net cash Net cash is a non-IFRS measure which does not have a standardised meaning prescribed by IFRS. Management uses this measure to analyse the financial strength of the Group. The measure is used to ensure capital is managed effectively in order to support its ongoing operations, and to raise additional funds, if required. USD'000 30 June 2022 30 June 2021 31 December 2021 Cash and cash equivalents, representing net cash of the Group 161,628 48,291 117,865 The cash and cash equivalents for the period ended 30 June 2021 includes restricted cash of US$1.0 million associated with an Indonesian performance bond that was returned in Q3 2021. 2022 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 quarterly 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 2022 remain unchanged from the risks disclosed in the 2021 Annual Report pages 57 to 63. 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, Paul Blakeley Executive Director President & Chief Executive Officer 20 September 2022 Condensed Consolidated Statement of Profit or Loss and Other Comprehensive Income for the six months ended 30 June 2022 Six months ended 30 June 2022 Six months ended 30 June 2021 Twelve months ended 31 December 2021 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Consolidated statement of profit or loss Revenue 225,639 138,158 340,194 Production costs 5 (83,401) (62,492) (206,523) Depletion, depreciation and amortisation 5 (35,135) (39,697) (80,215) Administrative staff costs (15,165) (12,067) (25,068) Other expenses 5 (5,503) (12,501) (26,181) Other income 5,602 3,681 7,682 Finance costs 6 (4,784) (3,934) (9,075) Other financial gains - - 266 Profit before tax 87,253 11,148 1,080 Income tax expense 7 (37,767) (8,653) (14,822) Profit/(Loss) for the period/year, representing total comprehensive income for the year 49,486 2,495 (13,742) Earnings/(Loss) per ordinary share Basic (US$) 8 0.11 0.01 (0.03) Diluted (US$) 0.10 0.01 (0.03) Condensed Consolidated Statement of Financial Position as at 30 June 2022 30 June 2022 30 June 2021 31 December 2021 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Assets Non-current assets Intangible exploration assets 9 77,027 96,443 93,241 Oil and gas properties 10 350,404 303,625 353,592 Plant and equipment 10 8,896 1,584 8,963 Right-of-use assets 10 9,288 18,358 13,852 Other receivables and prepayment 11 46,817 4,451 48,500 Deferred tax assets 14,366 16,318 25,278 Total non-current assets 506,798 440,779 543,426 Current assets Inventories 38,162 34,812 23,299 Trade and other receivables 11 28,588 63,135 37,951 Tax recoverable 7 8,162 - 9,367 Restricted cash - 1,000 - Cash and cash equivalents 161,628 47,291 117,865 Total current assets 236,540 146,238 188,482 Total assets 743,338 587,017 731,908 Equity and liabilities Equity Capital and reserves Share capital 12 1,229 391 559 Share based payments reserve 26,619 25,625 25,936 Merger reserve 14 146,270 146,270 146,270 Retained earnings/(Accumulated losses) 11,553 (12,710) (31,692) Total equity 185,671 159,576 141,073 Non-current liabilities Provisions 15 413,451 290,693 410,697 Lease liabilities 1,154 9,086 4,504 Deferred tax liabilities 59,032 54,564 67,097 Total non-current liabilities 473,637 354,343 482,298 30 June 2022 30 June 2021 31 December 2021 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Current liabilities Lease liabilities 9,576 11,625 11,161 Trade and other payables 16 46,575 22,760 69,090 Provisions 15 3,503 3,091 1,947 Tax liabilities 7 24,376 35,622 26,339 Total current liabilities 84,030 73,098 108,537 Total liabilities 557,667 427,441 590,835 Total equity and liabilities 743,338 587,017 731,908 Condensed Consolidated Statement of Changes in Equity for the six months ended 30 June 2022 Non-distributable reserve Share based Distributable reserves Share payments Merger Accumulated capital reserve reserve losses Total USD'000 USD''000 USD'000 USD'000 USD'000 As at 1 January 2021 466,979 24,985 - (331,322) 160,642 Profit for the period, representing total comprehensive income for the period - - - 2,495 2,495 Dividend paid - - - (5,000) (5,000) Share-based compensation - 640 - - 640 Shares issued 799 - - - 799 Capital reduction (467,387) - 146,270 321,117 - Total transactions with owners, recognised directly in equity (466,588) 640 146,270 316,117 (3,561) As at 30 June 2021 391 25,625 146,270 (12,710) 159,576 As at 1 January 2021 466,979 24,985 - (331,322) 160,642 Loss for the year, representing total comprehensive income for the year - - - (13,742) (13,742) Capital reduction (467,387) - 146,270 321,117 - Dividend paid - - - (7,745) (7,745) Share-based compensation - 951 - - 951 Shares issued 967 - - - 967 Total transactions with owners, recognised directly in equity (466,420) 951 146,270 313,372 (5,827) As at 31 December 2021 559 25,936 146,270 (31,692) 141,073 Non-distributable reserve Distributable reserves Share (Accumulated based losses)/ Share payments Merger Retained capital reserve reserve earnings Total USD'000 USD''000 USD'000 USD'000 USD'000 As at 1 January 2022 559 25,936 146,270 (31,692) 141,073 Profit for the period, representing total comprehensive income for the period - - - 49,486 49,486 Dividend paid - - - (6,241) (6,241) Share-based compensation - 683 - - 683 Shares issued 670 - - - 670 Total transactions with owners, recognised directly in equity 670 683 - (6,241) (4,888) As at 30 June 2022 1,229 26,619 146,270 11,553 185,671 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 2022 2021 2021 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Operating activities Profit before tax 87,253 11,148 1,080 Adjustments for: Depletion, depreciation and amortisation 5 28,988 33,338 69,024 Depreciation of right-of-use assets 5 / 10 6,147 6,359 11,191 Other finance costs 6 4,643 3,784 8,487 Share-based payments 683 640 951 Provision for doubtful debts 446 201 - Unrealised foreign exchange loss/(gain) 241 (735) (1,838) Interest expense 6 141 150 150 Assets written off 13 - 5,332 Interest income (2,074) (38) (80) Reversal of fair value loss on oil derivatives - (471) (471) Accretion income on non-current VAT receivables - - (266) Change in fair value of contingent payments - - 438 Allowance for slow moving inventories - - 2,624 Operating cash flows before movements in working capital 126,481 54,376 96,622 Decrease/(Increase) in trade and other receivables 10,505 (53,777) (11,975) (Increase)/Decrease in inventories (10,774) 5,719 9,152 (Decrease)/Increase in trade and other payables (22,389) (5,196) 21,631 Cash generated from operations 103,823 1,122 115,430 Interest paid (600) (768) (1,505) Tax refunded 12 - 3,652 Tax paid (34,189) (8,004) (15,486) Net cash generated/(used in) from operating activities 69,046 (7,650) 102,091 Six months Six months Twelve ended ended months ended 30 June 30 June 31 December 2022 2021 2021 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Investing activities Cash received from acquisition of Peninsular Malaysia assets - - 29,252 Cash paid for acquisition of Peninsular Malaysia assets - - (20,033) Payment for oil and gas properties 10 (10,687) (14,173) (51,380) Payment for plant and equipment 10 (253) (216) (682) Payment for intangible exploration assets 9 (2,424) (1,476) (3,858) Transfer from debt service reserve account - 7,445 8,445 Interest received 170 38 80 Net cash used in investing activities (13,194) (8,382) (38,176) Financing activities Net proceeds from issuance of shares 670 799 967 Dividends paid (6,241) (5,000) (7,745) Repayment of borrowings - (7,356) (7,296) Repayment of lease liabilities (6,518) (6,116) (12,972) Net cash used in financing activities (12,089) (17,673) (27,046) Net increase/(decrease) in cash and cash equivalents 43,763 (33,705) 36,869 Cash and cash equivalents at beginning of the period/year 117,865 80,996 80,996 Cash and cash equivalents at end of the period/year 161,628 47,291 117,865 Explanation Notes to the Condensed Consolidated Interim Financial Statements for the six months ended 30 June 2022 1. GENERAL INFORMATION Jadestone Energy plc (the "Company" or "Jadestone") is an oil and gas company incorporated in the United Kingdom and registered in England and Wales. The company registration number is 13152520 and the Company's shares are traded on AIM under the symbol "JSE". The financial statements are expressed in United States Dollars. The Group is engaged in production, development, exploration and appraisal activities in Australia, Malaysia, Vietnam and Indonesia. The Group's producing assets are in the Vulcan (Montara) and Carnarvon (Stag) basins, located in shallow water offshore of Western Australia, and in the East Piatu, East Belumut, West Belumut and Chermingat fields, located in shallow water offshore Peninsular Malaysia. The Company's head office is located at 3 Anson Road, #13-01 Springleaf Tower, Singapore 079909. The registered office of the Company is Suite 1, 3rd Floor, 11 - 12 St James's Square, London SW1Y 4LB. These financial statements were authorised for issue and release by the Company's Board of Directors on 20 September 2022. 2. SIGNIFICANT EVENT DURING THE PERIOD Montara operations update On 17 June 2022, between three to five cubic metres of crude oil was released to sea during a routine oil transfer between tanks on the Montara Venture FPSO. The facility was immediately shut-in as a precaution and the relevant authorities notified. Following a temporary repair and isolation of the 2C tank, production was restarted on 4 July 2022 while a permanent repair was being developed. On 12 August 2022, an additional defect was identified in a ballast water tank on the Montara Venture FPSO during preparation work for a permanent repair to the 2C tank. The Group took the decision to temporarily shut-in production at Montara to prioritise the permanent repairs due to an inability to simultaneously accommodate production and inspection and repair crews. 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PREPARATION These unaudited condensed consolidated interim financial statements (the "financial statements") are prepared in accordance with International Accounting Standard IAS 34 Interim Financial Reporting, as adopted by the European Union, on a going concern basis under the historical cost convention. These unaudited condensed consolidated interim financial statements do not comprise statutory accounts within the meaning of section 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 Jadestone's audited consolidated financial statements for the year ended 31 December 2021. Jadestone's auditors reported on those accounts; their report was unqualified and did not draw attention to any matters by way of emphasis. 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 As at 30 June 2022, the Group has a total cash and cash equivalents of US$161.6 million, and the Group managed to keep the cash levels within the range of US$110.0 - 160.0 million between July and August 2022, after the settlements of trade related expenditure. The average Dated Brent crude price in July and August 2022 was US$102.73/bbl, largely aligned with the average price during the first half of 2022. Hence the Group was able to continue to generate material cash inflows from the liftings in Australia and Malaysia subsequent to June 2022 end. ��� 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. All principal risk and uncertainties faced by the Group are disclosed in the 2021 Annual Report pages 57 to 63 and have been considered in the Group's near and longer term cash projections. The principal risk and uncertainties remain unchanged at the current period end. For the purposes of the Group's going concern assessment, we have reviewed cash projections for the period from 1 July 2022 to 31 December 2023, the 'going concern period'. Having taken into consideration the above factors, the Directors have reasonable expectation that the Group has adequate resources to 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 amendment that is relevant to the Group for the first time with effect from 1 January 2022. - Amendments to IAS 37 Onerous Contracts - Cost of Fulfilling a Contract - Amendments to IFRS 3 Reference to Conceptual Framework - Amendments to IFRSs Annual Improvements to IFRS Standards 2018 - 2020 The amendments are effective for annual periods beginning on 1 January 2022 and require prospective application. The adoption of these amendments has not resulted in changes to the Group's accounting policies. 4. CRITICAL ACCOUNTING JUDGMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY Climate change and energy transition The Group has assessed the potential impacts of climate change and the transition to a lower carbon economy in preparing these financial statements. The Group's assumptions relating to demand for oil and gas and their impact on the Group's long-term price assumptions remain the same as disclosed in the Jadestone's audited consolidated financial statements for the year ended 31 December 2021. The Group also takes into consideration the forecasted long-term prices and demand for oil and gas under the Paris aligned scenarios. The forecasted long-term prices and demand for oil and gas under the Paris aligned scenarios remain the same as disclosed in Jadestone's audited consolidated financial statements for the year ended 31 December 2021. Details of the Group's environment, social and governance ("ESG") plans and activities are disclosed in the 2021 Annual Report pages 26 to 49 and the ESG section above. 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 2021. 5. OPERATING COSTS Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2022 2021 2021 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Production costs 80,533 61,951 203,714 Tariffs and transportation costs 2,868 541 2,809 Total production costs 83,401 62,492 206,523 Depletion and amortisation of oil and gas properties 28,681 33,054 68,516 Depreciation of plant equipment and right-of-use assets 6,454 6,643 11,699 Total depletion, depreciation and amoritisation 35,135 39,697 80,215 Corporate costs 5,057 12,230 21,548 Other operating expenses 446 271 4,633 Total other expenses 5,503 12,501 26,181 6. FINANCE COSTS Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2022 2021 2021 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Interest expense and others 600 1,465 3,155 Accretion expense 4,184 2,469 5,920 4,784 3,934 9,075 7. INCOME TAX EXPENSE Six months ended 30 June 2022 Unaudited USD'000 Six months ended 30 June 2021 Unaudited USD'000 Twelve months ended 31 December 2021 Audited USD'000 Current tax Corporate tax charge/(credit) 29,154 11,405 (486) Overprovision in prior year - - (270) 29,154 11,405 (756) Australian petroleum resource rent tax ("PRRT") (162) (2,496) (1,374) Malaysian petroleum income tax ("PITA") 5,928 - 9,469 34,920 8,909 7,339 Deferred tax Corporate tax (4,042) (3,033) 5,247 PRRT 3,244 2,777 3,371 PITA 3,645 - (1,135) 2,847 (256) 7,483 37,767 8,653 14,822 8. EARNINGS/(LOSS) PER ORDINARY SHARE The calculation of the basic and diluted earnings/(loss) per share is based on the following data: Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2022 2021 2021 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Profit/(Loss) for the purposes of basic and diluted per share, being the net profit for the period attributable to equity holders of the Company 49,486 2,495 (13,742) Number Number Number Weighted average number of ordinary shares for the purposes of basic EPS 465,485,869 462,894,872 463,567,519 Effect of dilutive potential ordinary shares - share options 6,029,827 6,100,692 - Effect of dilutive potential ordinary shares - performance shares 595,998 - - Effect of dilutive potential ordinary shares - restricted shares 178,887 - - Weighted average number of ordinary shares for the purposes of diluted EPS 472,290,581 468,995,564 463,567,519 The calculation of diluted EPS for the six months ended 30 June 2022 includes 6,029,827 of weighted average dilutive ordinary shares available for exercise from in-the-money vested options (six months ended 30 June 2021: 6,100,692). The calculation of diluted EPS for the six months ended 30 June 2022 includes 595,998 of weighted average contingently issuable shares associated under the Company's performance share plan based on the respective performance measures up to the period end (six months ended 30 June 2021: nil). The calculation of diluted EPS for the six months ended 30 June 2022 includes 178,887 of weighted average contingently issuable shares under the Company's restricted share plan (six months ended 30 June 2021: nil). Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2022 2021 2021 Earnings/(Loss) per share (US$) Unaudited Unaudited Audited - - Basic 0.11 0.01 (0.03) - - - Diluted 0.10 0.01 (0.03) 9. INTANGIBLE EXPLORATION ASSETS Total USD'000 Cost As at 1 January 2021 151,125 Additions 1,832 Reversal (6,059) Written off (50,455) As at 30 June 2021 96,443 Additions 2,102 Changes in asset retirement obligations (44) Written off (5,260) As at 31 December 2021 93,241 Additions 2,681 Reclassification (18,895)* As at 30 June 2022 77,027 Impairment As at 1 January 2021 50,455 Additions (50,455) As at 30 June 2021/31 December 2021/30 June 2022 - Net book value As at 30 June 2021 (unaudited) 96,443 As at 31 December 2021 (audited) 93,241 As at 30 June 2022 (unaudited) 77,027 * The reclassification of US$18.9 million relates to the Lemang PSC in Indonesia. On 6 June 2022, the final investment decision was taken following regulatory approval to award the engineering, procurement, construction and installation ("EPCI") contract which established commercial viability. The capitalised cost of US$18.9 million was transferred to development assets as disclosed in Note 10. 10. 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 2021 496,992 - 4,612 45,514 547,118 Additions 14,173 - 216 1,044 15,433 As at 30 June 2021 511,165 - 4,828 46,558 562,551 Changes in asset restoration obligations 23,894 - - - 23,894 Acquisition of PenMal Assets 21,744 - - - 21,744 Additions 38,691 - 466 1,810 40,967 Written off - - (169) - (169) Transfer - - 7,209 - 7,209 As at 31 December 2021 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 Accumulated depletion, depreciation and amortisation As at 1 January 2021 179,316 - 2,960 21,841 204,117 Charge for the period 28,224 - 284 6,359 34,867 As at 30 June 2021 207,540 - 3,244 28,200 238,984 Charge for the period 34,362 - 224 6,316 40,902 Written off - - (97) - (97) As at 31 December 2021 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 Net book value As at 30 June 2021 (unaudited) 303,625 - 1,584 18,358 323,567 As at 31 December 2021 (audited) 353,592 - 8,963 13,852 376,407 As at 30 June 2022 (unaudited) 331,509 18,895 8,896 9,288 368,588 11. TRADE AND OTHER RECEIVABLES 30 June 2022 30 June 2021 31 December 2021 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Non-current Other receivables At beginning of period/year 41,726 - - Acquisition of PenMal Assets - - 42,092 Change in asset restoration obligations - - (672) Cess paid 169 - 306 At end of period/year 41,895 - 41,726 Prepayment - - 2,000 VAT receivables 4,922 4,451 4,774 46,817 4,451 48,500 Current Trade receivables 535 46,291 9,143 Prepayments 7,166 6,093 3,770 Other receivables and deposits 2,175 6,621 13,281 Amount due from joint arrangement partners (net) 226 - 2,203 Underlift crude oil inventories 16,802 - 6,855 PRRT receivables 162 2,496 - GST/VAT receivables 1,522 1,634 2,699 28,588 63,135 37,951 75,405 67,586 86,451 12. SHARE CAPITAL No. of shares USD'000 Issued and fully paid As at 1 January 2021 461,842,811 466,979 Issued during the period 1,856,666 800 Capital reduction, at ��0.499 each - (467,388) As at 30 June 2021 463,699,477 391 Issued during the period 1,381,761 168 As at 31 December 2021 465,081,238 559 Issued during the period 972,378 670 As at 30 June 2022 466,053,616 1,229 The Company has one class of ordinary share. Fully paid ordinary shares carry one vote per share without restriction, and carry a right to dividends as and when declared by the Company. 13. DIVIDEND On 6 June 2022, the Directors declared the 2021 final dividend of 1.34 US cents/share, equivalent to 1.07 GB pence/share based on the spot exchange rate of 0.7954, equivalent to a total distribution of US$6.2 million. The dividend was paid on 5 July 2022. 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. PROVISIONS 30 June 2022 30 June 2021 31 December 2021 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Non-current Asset restoration obligations 408,585 286,219 404,400 Others 4,866 4,474 6,297 413,451 290,693 410,697 Current Others 3,503 3,091 1,947 416,954 293,784 412,644 16. TRADE AND OTHER PAYABLES 30 June 2022 Unaudited USD'000 30 June 2021 Unaudited USD'000 31 December 2021 Audited USD'000 Trade payables 5,602 3,377 26,847 Other payables 4,862 1,662 7,627 Accruals 33,267 17,714 29,699 Contingent payment - - 3,000 Malaysian supplementary payment payables 2,839 - 1,907 GST/VAT payables 5 7 10 46,575 22,760 69,090 17. SEGMENT INFORMATION Information reported to the Group's Chief Executive Officer (the chief operating decision maker) for the purposes of resource allocation is focused on two reportable/business segments driven by different types of activities within the upstream oil and gas value chain, namely producing assets and 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 2022 (unaudited) Revenue Liquids revenue 175,476 48,256 - - 223,732 Gas revenue - 1,907 - - 1,907 175,476 50,163 - - 225,639 Production cost (58,792) (24,609) - - (83,401) 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 5,185 54 14 349 5,602 Finance costs (3,397) (1,173) (200) (14) (4,784) Profit/(Loss) before tax 75,943 20,022 (2,155) (6,557) 87,253 Additions to non- current assets 12,303 322 2,829 67 15,521 Non-current assets 340,094 58,084 93,650 604 492,432 Producing assets Exploration/ development Australia USD'000 SEA USD'000 SEA USD'000 Corporate USD'000 Total USD'000 Six months ended 30 June 2021 (unaudited) Revenue Liquids revenue 138,158 - - - 138,158 Hedging income - - - - - 138,158 - - - 138,158 Production costs (62,492) - - - (62,492) DD&A (39,261) - (139) (297) (39,697) Administrative staff costs (5,137) - (1,397) (5,533) (12,067) Other expenses (8,807) - (897) (2,797) (12,501) Other income 3,257 - 36 388 3,681 Finance costs (3,907) - (26) (1) (3,934) Profit/(Loss) before tax 21,811 - (2,423) (8,240) 11,148 Additions to non- current assets 14,971 - 2,145 196 17,312 Non-current assets 329,830 - 93,789 842 424,461 Twelve months ended 31 December 2021 (audited) Revenue Liquids revenue 293,566 45,644 - - 339,210 Gas revenue - 984 - - 984 293,566 46,628 - - 340,194 Production cost (182,001) (24,522) - - (206,523) DD&A (75,848) (3,621) (281) (465) (80,215) Administrative staff costs (13,364) (1,433) (1,612) (8,659) (25,068) Other expenses (14,970) (2,466) (5,875) (2,870) (26,181) Other income 7,038 9 76 559 7,682 Finance costs (7,452) (875) (503) (245) (9,075) Other financial gains - - 266 - 266 Profit/(Loss) before tax 6,969 13,720 (7,929) (11,680) 1,080 Additions to non- current assets 57,130 64,117 4,744 183 126,174 Non-current assets 366,959 59,532 90,938 719 518,148 Non-current assets as shown here comprises oil and gas properties, intangible exploration assets, right-of-use assets, other receivables, restricted cash and plant and equipment used in corporate offices. Deferred tax assets are excluded from the segmental note but included in the Group's consolidated statement of financial position. 18. EVENTS AFTER THE REPORTING PERIOD Acquisition of the interest in North West Shelf oil producing fields On 28 July 2022, the Group announced the execution of a sale and purchase agreement with BP Developments Australia Pty Ltd to acquire BP's non-operated 16.67% working interest in the Cossack, Wanaea, Lambert and Hermes oil field development, offshore Australia. The total headline consideration is US$20.0 million plus an upfront payment of US$41.0 million into a decommissioning trust fund with two further equal instalments of US$20.5 million into the decommissioning trust fund due on or about 31 December 2022 and 2023, respectively. The effective date of the transaction is 1 January 2020 and the economic benefits from the effective date until the closing date will be adjusted in the final consideration price. Completion of the transaction is subject to customary closing conditions including various regulatory approvals. The Group anticipates completion of the transaction to occur in Q4 2022. Launch of the share buyback programme On 2 August 2022, the Company launched a share buyback programme in accordance with the authority granted by the shareholders at the Company's Annual General Meeting held on 30 June 2022. The maximum pecuniary amount of the programme is US$25.0 million and the programme will not exceed 46,574,528 ordinary shares. There is no certainty on the volume of shares that may be acquired, nor any certainty on the pace and quantum of the acquisitions. Glossary �� British pound sterling 2C best estimate contingent resource, being quantities of hydrocarbons which are estimated, on a given date, to be potentially recoverable from known accumulations but which are not currently considered to be commercially recoverable AAKBNLP Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields AIM Alternative Investment Market API American Petroleum Institute gravity bbl barrel bbls/d barrels per day boe barrels of oil equivalent boe/d barrels of oil equivalent per day capex capital expenditures DD&A depletion, depreciation and amortisation EBITDAX earnings before interest tax, depreciation, amortisation and exploration EPS earnings per share FPSO floating production storage and offloading GB pence, GBp Great Britain pence GHG greenhouse gases GST goods and services tax IFRS International Financial Reporting Standards LPG Liquefied petroleum gas LTI Lost Time Injury mm million mscf/d thousand standard cubic feet per day mmscf million standard cubic feet opex operating expenditures PenMal Assets Peninsular Malaysia Assets PITA Malaysian Petroleum Income Tax PRRT Petroleum Resource Rent Tax PSC production sharing contract reserves hydrocarbon resource that is anticipated to be commercially recovered from known accumulations from a given date forward SEA Southeast Asia US$ or USD United States dollar VAT value-added tax 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. This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. 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