JADESTONE ENERGY PLC

Earnings Release • Sep 9, 2021

National Storage Mechanism | Additional information RNS Number : 2436L Jadestone Energy PLC 09 September 2021 2021 Half Year Results and Interim Dividend Declaration 9 September 2021-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 2021 (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: "I am pleased to report a solid 2021 first half across the business, with production from our Australian assets slightly better than expected, ahead of implementing the activity plan on Montara and Stag that was deferred from last year due to low oil prices. I am also pleased to report safe operational performance through the year to date, while we remain vigilant on the well-being of our workforce given the continued significant impact of the COVID-19 pandemic. "During the period, global demand for hydrocarbons has been recovering, creating strong market fundamentals including an increase in benchmark oil prices. Jadestone's average oil price realisations in the first half were 45% higher than the same period last year. This translated into positive operating cash flows of US$54.4 million in H1 2021. Adding the proceeds of a June Montara lifting which were received in early July, pro-forma cash balances at mid-year were just short of US$100 million. "With no debt, our financial position at the end of the first half was very strong, allowing us to increase the interim dividend by 10%. Going forward, we will continue to balance dividend growth against the significant organic and inorganic growth opportunities, and associated capital needs, across the business. "I am particularly pleased with the Peninsular Malaysia acquisition announced during H1 2021. Due to the concerted efforts of our team, we closed the transaction just three months after announcing, with net cash due to Jadestone of US$9.2 million. Further, we remain committed to our acquisition of a 69% operated interest in the Maari project, shallow water offshore New Zealand, and remain confident that the transaction will be completed, though timing of government approvals is beyond our control. "Our gas developments have also seen positive progress during the first half. At Lemang, in Indonesia, the regulator has allocated future gas sales from the project, which provides certainty as we work toward both formalising gas sales contracts and progressing the various workstreams leading toward a final investment decision. In Vietnam, we have re-engaged with regulators to press toward a target for both the production profile and first gas date, as a key precursor to establishing gas sales agreement details. "Today, we have reaffirmed production guidance for 2021 of 11,500 - 13,500 boe/d, key to which is the contribution of the H6 development well on Montara, which is currently in the completions phase before being tied in and brought onstream shortly. This well, together with the Skua workovers and the contribution of the Peninsular Malaysia assets, would give us clear line of sight on a production rate of 20,000 boe/d towards the end of the year." Paul Blakeley EXECUTIVE DIRECTOR, PRESIDENT AND CHIEF EXECUTIVE OFFICER 2021 FIRST HALF RESULTS SUMMARY USD'000 except where indicated H1 2021 H1 2020 FY 2020 Production, bbls/day 9,934 12,116 11,438 Realised oil price per barrel (US$/bbl)1 67.70 46.47 44.79 Revenue2 138,158 115,669 217,938 Operating costs per barrel (US$/bbl)3 28.16 23.27 23.10 Adjusted EBITDAX3 65,179 36,606 62,582 Profit/(Loss) after tax 2,495 5,360 (60,178)4 Earnings/(Loss) per ordinary share: basic & diluted (US$) 0.01 0.01 (0.13) Dividend per ordinary share (US��) 0.59 0.54 1.62 Operating cash flows before movement in working capital 54,376 57,054 86,883 Capital expenditure 16,221 19,521 24,065 Outstanding debt3 - 25,574 7,386 Net cash3 48,291 78,281 82,055 Financial l H1 2021 production of 9,934 bbls/d, slightly ahead of plan but 18% lower than H1 2020, in part due to natural field production decline, deferred workovers and an unplanned shutdown at Montara for critical valve repairs; l Average realised oil prices1 in H1 2021 were US$67.70/bbl, 46% higher than H1 2020. Realised prices included an average premium over the benchmark of US$3.12/bbl5 (H1 2020: US$8.19/bbl); l Net revenue for H1 2021 of US$138.2 million, up 50% from H1 2020 before hedging income2, due to the increase in oil prices since the beginning of 2021 and higher lifted volumes; l Unit operating costs6 of US$28.16/bbl, up 21% from H1 2020 of US$23.27/bbl, in part due to lower production, coupled with higher operational staff costs and repair & maintenance costs; l Net profit after tax of US$2.5 million, down from US$5.4 million in H1 2020, which includes the impact of several one-off expenses of US$3.4 million arising from costs associated with the acquisition of SapuraOMV Upstream (PM) Inc. as well as other business development costs and costs associated with the corporate reorganisation, and a net hedging loss of US$4.6 million; l H1 2021 positive operating cash flows of US$54.4 million, before movements in working capital, down 5% compared to H1 2020; l Capital expenditure of US$16.2 million, down 17% compared to the prior period. Capital expenditure incurred in H1 2021 is primarily related to costs of the drilling of the H6 development well at Montara. H1 2020 development spend was primarily on the Nam Du/U Minh field prior to the project activity being deferred during the early stages of the COVID-19 pandemic; l The 2018 reserves based loan was fully repaid on 31 March 2021, leaving the Group now entirely free of any interest bearing financial indebtedness; l Net cash as at 30 June 2021 of US$48.3 million (H1 2020: US$78.3 million) and zero outstanding debt (H1 2020: US$25.6 million). The lower gross cash balance is partly due to timing differences in liftings, with proceeds of US$46.1 million from a Montara June 2021 lifting received in July 2021; and l A 2021 interim dividend of 0.59 US cents/share has been declared. 1 Realised oil price represents the actual selling price and before any impact from hedging. The H1 2020 realised price is net of marketing fees of US$0.08/bbl, whereas full year 2020 and H1 2021 realised oil prices are before marketing fees which are recorded in production costs pursuant to IFRS 15 Revenue from Contracts with Customers. 2 Revenue in H1 2020 and FY 2020 includes hedging income of US$23.7 million and US$31.4 million, respectively, pursuant to the characterisation of the two-year capped swap programme as cashflow hedges under IFRS9 Financial Instruments. Losses realised on the H1 2021 swaps of US$4.6 million have been recognised in other expenses, pursuant to the characterisation of the ad hoc H1 2021 six-month swap programme as derivative instruments measured at fair value through profit or loss. The H1 2021 swap programme covered a short time span (not exceeding a half yearly reporting period), whereas the capped swap programme crossed three annual reporting periods. 3 Operating costs per bbl, adjusted EBITDAX, outstanding debt and net cash are non-IFRS measures and are explained below. 4 Loss after tax for the year ended 31 December 2020 included an impairment of US$50.5 million associated with the capitalised intangible exploration costs at SC56. 5 With the change to the shuttle tanker model at Stag, the premium negotiated for each Stag lifting is now typically based on a CIF (cost, insurance and freight) basis rather than a FOB (free on board) basis. Care needs to be taken in making comparisons with 2020 premia for the period up until September 2020 when the switch to the tanker model occurred. 6 Unit operating costs per barrel before workovers, but including net lease payments and certain other adjustments (see non-IFRS measures below). Business development l Announced the acquisition of SapuraOMV's interests in Peninsular Malaysia for an initial headline cash consideration of US$9.0 million, plus customary adjustments and certain subsequent contingent payments. The acquisition was completed on 1 August 2021, resulting in a net cash receipt of US$9.2 million after adjustments; and l Both Jadestone and the Maari seller continue to work to satisfy the remaining outstanding conditions to complete the Maari acquisition. Guidance l Full year guidance unchanged from 18 August 2021 update: o Production: 11,500 - 13,500 boe/d; o Unit opex: US$25.50 - 29.50/boe; and o Capex: US$105 - 115 million. Enquiries Jadestone Energy plc +65 6324 0359 (Singapore) Paul Blakeley, President and CEO Dan Young, CFO +44 7713 687 467 (UK) Phil Corbett, Investor Relations Manager 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 / 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, Thursday, 9 September 2021, 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 2021 will be available on the Company's website at: www.jadestone-energy.com/investor-relations/ Webcast link: https://produceredition.webcasts.com/starthere.jsp?ei=1485258&tp_key=efaeb2a81e Event conference title: Jadestone Energy plc - Half Year Results Start time: 9:00 a.m. (London)/4:00 p.m. (Singapore) Date: Thursday, 9 September 2021 Conference ID: 24719928 Dial-in number details: Country Dial-In Numbers United Kingdom 08006522435 Australia 1800076068 Canada (Toronto) 416-764-8688 Canada (Toll free) 888-390-0546 New Zealand 0800453421 Singapore 8001013217 United States (Toll free) 888-390-0546 France 0800916834 Germany 08007240293 Germany (Mobile) 08007240293 Hong Kong 800962712 Indonesia 0078030208221 Ireland 1800939111 Ireland (Mobile) 1800939111 Japan 006633812569 Malaysia 1800817426 Switzerland 0800312635 Switzerland (Mobile) 0800312635 DIVIDEND DECLARATION On 9 September 2021, the directors have declared a 2021 interim dividend of 0.59 US cents/share (or equivalent to 0.43 GB pence/share based on the current spot exchange rate of 0.7257), equivalent to a total distribution of US$2.8 million. The dividend will be paid on a gross basis, in US dollars. The timetable for the dividend payment is as follows: l Ex-dividend date: 16 September 2021 l Record date: 17 September 2021 l Payment date: 1 October 2021 The Company's growth-oriented strategy remains unchanged; the business model is highly cash-generative, and, as a result, is fundamentally pre-disposed to providing cash returns, after allowing for organic reinvestment needs, whilst maintaining a conservative capital structure, and not unduly limiting options for further inorganic growth. The Company intends to maintain and grow the dividend over time, in line with underlying cash flow generation. The Company does not offer a dividend reinvestment plan, and does not offer dividends in the form of ordinary shares. ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG") As a leading oil and gas development and production company in the Asia Pacific region, Jadestone strives to deliver sustainable value for all of its stakeholders in a safe, secure, environmentally and socially responsible manner. Jadestone published its second Sustainability Report in June this year, which covered the Group's approach to ESG and performance across key focus areas for the 2020 calendar year, as well as commitments to further improvements in 2021. ESG Performance Through H1 2021, the Group maintained safe operations and had no significant recordable personnel or environmental incidents, and no disruptions to offshore operations due to the COVID-19 pandemic. Jadestone has committed to 2021 ESG targets across all of its material matters, which form a part of annual executive key performance indicators, translating directly to performance pay. Jadestone has continued its focus on reducing the carbon footprint of its operations, through the work of the Operational and Executive subgroups of the Climate Change Working Group ("CCWG"). In 2021, the Company is targeting a 5% reduction in both flared volumes and diesel use compared to 2020 levels. Initiatives to reduce GHG emissions in 2021 include: l continuing to increase the uptime of the reinjection compressor at the Montara asset; l prioritising usage of produced gas over diesel to run Montara operations; and l enhancing internal GHG emissions reporting to support improved operational practices. The Operational CCWG is currently reviewing the recently acquired Peninsular Malaysia assets to identify sources of emissions, opportunities to reduce emissions, as well as integrating asset-level GHG reporting. The Company has also been rolling out its community engagement programmes in all countries of operations, to further enhance its positive contribution to the local communities. Throughout 2021, the focus in the regions has been on identifying most pressing community needs and looking for optimal channels of delivery, that prioritise employee safety. Jadestone has also continued its employee-facing programmes, including running the Plastic Free July campaign, where feasible. UN Sustainable Development Goals Jadestone's ESG framework continues to align with the wider societal challenges addressed by the UN's Sustainable Development Goals ("SDGs"). Whilst its business activities touch directly or indirectly on many of the SDGs, Jadestone has selected the goals that most closely align with its current business strategy, activities, values and purpose. These are set out in the Company's Sustainability Report, contained within the 2020 Annual Report. Task Force on Climate-Related Financial Disclosures In 2020, Jadestone commenced its alignment with the Task Force on Climate-Related Financial Disclosures ("TCFD"), utilising it as a practical tool for navigating the transition to a low-carbon economy and increasing business resiliency. In H1 2021 the Company has continued to implement the TCFD recommendations in its reporting and programmes, with a particular focus on climate risk integration and strategy considerations. Jadestone will disclose its progress in TCFD adoption in its 2021 Sustainability Report, to be published in H1 2022. Governance The Group adopted the Quoted Companies Alliance corporate governance code ("QCA code") at the end of 2020. The resultant changes that arise from the adoption of the QCA code have been implemented and are a testament to the Company's commitment to further strengthening transparent and effective corporate governance practices. Further details and enhanced disclosures of ESG can be found in the Company's 2020 Sustainability Report, as part of the 2020 Annual Report, from pages 36 to 81. OPERATIONAL REVIEW Producing assets Australia Montara project The Montara assets, in production licences AC/L7 and AC/L8, are located 254km offshore Western Australia, in a water depth of approximately 77 metres. The Montara assets, comprising the three separate fields being Montara, Skua and Swift/Swallow, are produced through an owned FPSO, the Montara Venture. As at 31 December 2020, the Montara assets had proven plus probable reserves of 23.4mm barrels of oil, 100% net to Jadestone. The fields produce light sweet crude (42o API, 0.067% mass sulphur), which typically sells at a premium to Dated Brent. The premium in H1 2021 ranged between US$0.39/bbl to US$0.66/bbl. The most recent lifting was agreed at a premium of US$1.17/bbl. During H1 2021, there was an unplanned shutdown to replace a significant number of critical valves on the FPSO. The shutdown was for 16 days resulting in around 102,000 bbls of deferred production. The original valves were installed during the FPSO's construction and the replacements should last for the remaining life of the field. The Montara assets produced an average of 7,269 bbls/d in the first half of 2021 (H1 2020: 9,440 bbls/d). This was lower than H1 2020 in part due to natural field production decline and the unplanned shutdown to replace the defective critical valves. The Group took the Valaris 107 drilling rig on hire on 14 June 2021 and commenced drilling the H6 development well on 28 June 2021. During the initial attempt to drill the horizontal section in the well, mechanical issues with downhole equipment resulted in a deviation from the planned well path, which necessitated a sidetrack. The sidetrack was successful, resulting in a circa 1,200 metre horizontal section in the reservoir, encountering good quality oil-bearing sands. The well is currently in the completions phase before being tied in to the Montara infrastructure, after which the rig will proceed with the Skua 11 and 10 workovers. There were three liftings during H1 2021, resulting in total sales of 1,536,307 bbls, compared to 1,461,096 bbls in H1 2020 from the same number of liftings. Stag oilfield The Stag oilfield, in block WA-15-L, is located 60km offshore Western Australia, in a water depth of approximately 47 metres. As at 31 December 2020, the field contained total proved plus probable reserves of 13.7mm 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 in 2021 ranged between US$8.30/bbl to US$13.88/bbl1. The most recent lifting was agreed at a premium of US$10.15/bbl. During H1 2021, the Group continued its workover and maintenance programme. As a result of COVID-19 constraints, production continues to be impacted by a backlog of workovers that are scheduled to be complete by the end of 2021. Production was 2,665 bbls/d during H1 2021, compared to 2,676 bbls/d in H1 2020. There were two liftings during H1 2021, generating total sales of 504,485 bbls, compared to 518,193 bbls in H1 2020 from the same number of liftings. Malaysia PM 323 and PM 329 PSCs (operated), PM 318 and AAKBNLP PSCs (non-operated) On 30 April 2021, the Group announced the execution of a sale and purchase agreement ("SPA") with SapuraOMV Upstream Sdn. Bhd. ("SapuraOMV") to acquire SapuraOMV's Peninsular Malaysia assets (the "PenMal Assets"), for an initial cash consideration of US$9.0 million, plus customary adjustments. Further contingent payments of up to US$6.0 million are payable to SapuraOMV, which are tied to potential full year oil price outcomes in 2021 and 20222. The acquisition completed on 1 August 2021, following the satisfaction of all conditions precedent, resulting in a total final cash consideration of US$20.0 million, comprising the headline cash consideration of US$9.0 million plus adjustments of US$11.0 million. The economic effective date of the acquisition was 1 January 2021, meaning the Group was entitled to all net cash generated since 1 January 2021 up to the completion date. As a result, at completion the Group obtained cash held by SapuraOMV Upsteam (PM) Inc. of US$29.2 million, resulting in a net cash receipt of US$9.2 million from the acquisition. The PenMal Assets consist of four licences, two of which are operated by the Group. The two operated licences comprise a 70% operated interest in the PM329 PSC, containing the East Piatu field, and a 60% operated interest in the PM323 PSC, which contains the East Belumut, West Belumut and Chermingat fields. Both PSCs are located approximately 230km northeast of Terengganu. All fields are in production, and have been developed by way of fixed wellhead and central processing platforms. The two non-operated licences consist of 50% working interests in each of the PM318 PSC and in the Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields ("AAKBNLP") PSC. The PenMal Assets add immediate cash flow from around 6,000 barrels of oil equivalent per day of low operating cost production, on a net working interest basis, of which over 90% is oil. The Group's Malaysian operated assets produce a very light sweet crude that is blended to Tapis grade (43 API, 0.04% mass sulphur). The PenMal Assets also increase the Group's 2P reserves by 34%, adding 12.5mm boe, representing the net working interest 2P reserves as at 31 December 2020, based on Jadestone's best estimate 2P reserves production profile. 1 With the change to the shuttle tanker model at Stag, the premium negotiated for each Stag lifting is now typically based on a CIF basis rather than a FOB basis. Care needs to be taken in making comparisons with 2020 premia for the period up until September 2020 when the switch to the tanker model occurred. 2 If the average daily price of Dated Brent crude oil in calendar 2021 (calendar 2022) exceeds US$65/bbl (US$70/bbl), then Jadestone pays SapuraOMV an additional US$3.0 million (US$3.0 million). The Group believes there is scope to add incremental value in the near term through both reservoir optimisation and production enhancement activities across both operated licences. Gas re-injection is expected to be a key part of reservoir optimisation, while production enhancement will initially be focused on restoring idle wells to production. There is also significant potential for further development activity on the PenMal Assets. The focus will initially be on infill drilling in the East Belumut field within the PM 323 PSC, where the Group sees the potential for several infill campaigns over the next few years. East Belumut has a medium heavy oil, which is similar to the Stag field offshore Australia, where we have experience of increasing recovery factors through tightening of the well pattern. There are also some targeted opportunities on the East Piatu and West Belumut fields, which will be evaluated in parallel with the East Belumut infill potential. In H1 2021, average production from the PenMal assets was 12,560 boe/d, equivalent to 7,492 boe/d, net to Jadestone's working interest. The net average realised prices incorporated into the liftings was US$65.90/bbl. Pending acquisition New Zealand Maari oilfield On 16 November 2019, the Group executed an SPA with OMV New Zealand Limited ("OMV New Zealand"), to acquire an operated 69% interest in the Maari project, located 120km offshore New Zealand, in a water depth of 100 metres, for a total headline cash consideration of US$50.0 million and subject to customary closing adjustments. The transaction has achieved several key milestones with regard to regulatory approvals, and the Group continues to focus on securing the remaining ministerial consents from the New Zealand Government, including the approval for transfer of operatorship. Jadestone and OMV New Zealand continue to work towards completion of the transaction, including extending the long stop date under the SPA from 31 August 2021 to 31 December 2021, as announced on 8 September 2021. The Group would assume the operatorship of the Maari project upon completion of the transaction. The economic benefits from 1 January 2019 until the closing date will be adjusted in the final consideration price. This is now anticipated to be a net receipt to the Group. As at 31 December 2020, the Maari project holds net 2P audited reserves of 10.6mm barrels of oil. Pre-production assets Vietnam Block 51 PSC and Block 46/07 PSC Jadestone holds a 100% operated working interest in Block 46/07 PSC and Block 51 PSC, both in shallow waters in the Malay Basin, offshore Southwest Vietnam. The two contiguous blocks hold three discoveries: the Nam Du gas field in Block 46/07 and the U Minh and Tho Chu gas/condensate fields in Block 51, with 2C resources of 93.9mm boe. The formal field development plan ("FDP") in respect of the Nam Du/U Minh development was submitted to the Vietnam regulatory authorities in late 2019. The Group deferred the project in mid-March 2020, amid delays in Vietnamese Government approvals and the drop in global oil prices due to COVID-19. Discussions are continuing with Petrovietnam to agree a gas production profile for the development, as a precursor to a gas sales contract, and ultimately attaining government sanction for the field development. Indonesia Lemang PSC The Lemang PSC is located onshore Sumatra, Indonesia. The block includes the Akatara gas field, with a net to Jadestone 2C resource of 16.8mm boe. The asset has been substantially de-risked with 11 wells drilled into the structure, plus three years of oil production history, up until the field ceased production of oil in December 2019. On 30 June 2021, the Minister of Mines and Energy of Indonesia issued a Ministerial decree, allocating gas sales from the Akatara gas field in the Lemang PSC to a subsidiary of the national electricity utility, PT Perusahaan Listrik Negara ("PLN"). The Ministerial decree facilitates the development and commercialisation of the Akatara gas field and also the associated production and sales of liquefied petroleum gas to the local domestic market in Jambi, together with condensate sales to a local buyer. A heads of agreement ("HoA") in relation to gas sales from Jadestone's planned development has also been executed with the PLN subsidiary, PT Pelayanan Listrik Nasional Batam ("PLN Batam"), as buyer. A fully termed gas sales agreement is currently under negotiation with PLN Batam. The Ministerial decree and HoA specify a gross sales volume of 20 BBtu/d starting in Q1 2024, and a plant gate sales price of US$5.60/mmBtu, at a delivery point approximately 17 kilometres from the field. Indonesia's upstream regulator, SKK Migas, has approved the HoA which is fully aligned with the Ministerial decree. Exploration assets Philippines Service Contract 56 ("SC56") Jadestone held a 25% interest in SC56 in partnership with operator Total E&P Philippines B.V. ("Total"). On 18 November 2020, Total and Jadestone expressed their intention to the Philippines Department of Energy ("DOE") to voluntarily surrender the entire interest in SC56 and accordingly, to terminate the contract. The effective date of termination was 21 December 2020. Following the termination, the Group is liable for 25% of the unfulfilled minimum work programme as at the termination date. At the end of June 2021, the Group received the finalised unfulfilled commitment amount from the DOE and is required to pay US$1.5 million, net 25% to Jadestone. The payment of this unfulfilled commitment amount will be funded from the net arbitration proceeds of US$2.2 million received from Total in 2020. Service Contract 57 ("SC57") The Group holds a 21% working interest in SC57, but it has been under force majeure since 2011, and these conditions are expected to continue for the foreseeable future. FINANCIAL REVIEW The following table provides selected financial information of the Group, which was derived from, and should be read in conjunction with, the unaudited condensed consolidated interim financial statements for the period ended 30 June 2021. USD'000 except where indicated Six months ended 30 June 2021 Six months ended 30 June 2020 Twelve months ended 31 December 2020 Sales volume, barrels (bbls) 2,040,792 1,979,289 4,165,612 Production, bbls/day 9,934 12,116 11,438 Realised oil price per barrel (US$/bbl)1 67.70 46.47 44.79 Revenue2 138,158 115,669 217,938 Production costs (62,492) (44,466) (105,338) Operating costs per barrel (US$/bbl)3 28.16 23.27 23.10 Adjusted EBITDAX3 65,179 36,606 62,582 Unit depletion, depreciation & amortisation (US$/bbl) 15.70 16.14 16.24 Impairment - - 50,455 Profit/(Loss) before tax 11,148 12,787 (57,238) Profit/(Loss) after tax 2,495 5,360 (60,178) Earnings/(Loss) per ordinary share: basic & diluted (US$) 0.01 0.01 (0.13) Dividend per ordinary share (US��) 0.59 0.54 1.62 Operating cash flows before movement in working capital 54,376 57,054 86,883 Capital expenditure 16,221 19,521 24,065 Outstanding debt3 - 25,574 7,386 Net cash3 48,291 78,281 82,055 Benchmark commodity price and realised price The average benchmark Dated Brent crude oil price increased 62% to US$64.98/bbl in the first half of 2021, compared to US$40.07/bbl in H1 2020. The average benchmark Dated Brent oil price incorporated into the Group's liftings was US$64.58/bbl in H1 2021, a 68% increase compared to US$38.36/bbl in H1 2020. 1 Realised oil price represents the actual selling price and before any impact from hedging. The H1 2020 realised price is net of marketing fees of US$0.08/bbl, whereas full year 2020 and H1 2021 realised oil prices are before marketing fees which are recorded in production costs pursuant to IFRS 15 Revenue from Contracts with Customers. With the change to the shuttle tanker model at Stag, the premium negotiated for each Stag lifting is now typically based on a CIF basis rather than a FOB basis. Care needs to be taken in making comparisons with 2020 premia for the period up until September 2020 when the switch to the tanker model occurred. 2 Revenue in H1 2020 and FY 2020 includes hedging income of US$23.7 million and US$31.4 million, respectively, pursuant to the characterisation of the two-year capped swap programme as cashflow hedges under IFRS9 Financial Instruments. Losses realised on the H1 2021 swaps of US$4.6 million have been recognised in other expenses, pursuant to the characterisation of the ad hoc H1 2021 six-month swap programme as derivative instruments measured at fair value through profit or loss. The H1 2021 swap programme covered a short time span (not exceeding a half yearly reporting period), whereas the capped swap programme crossed three annual reporting periods. 3 Net cash at June 2021 excludes a Montara June lifting of US$46.1 million, the proceeds of which were received in July 2021 (by comparison, there were no Montara or Stag liftings in December 2020 or June 2020). Operating costs per bbl, adjusted EBITDAX, outstanding debt and net cash are non-IFRS measures and are explained below. The actual average realised price in H1 2021 increased by 46% to US$67.70/bbl, compared to US$46.47/bbl in H1 2020. The average premium during the period was US$3.12/bbl, compared to US$8.19/bbl in H1 2020. Premiums continue to improve with the latest liftings achieving US$10.15/bbl and US$1.17/bbl at Stag and Montara, respectively. With the change to the shuttle tanker model at Stag, the premium negotiated for each Stag lifting is now typically based on a CIF basis rather than a FOB basis. Care needs to be taken in making comparisons with 2020 premia for the period up until September 2020 when the switch to the tanker model occurred. Production and liftings The Group generated average production in H1 2021 of 9,934 bbls/d (H1 2020: 12,116 bbls/d). Production at Montara was lower compared to H1 2020, primarily the result of natural field production decline and an unplanned shutdown at Montara for 16 days resulting in around 102,000 bbls of deferred production. The Group had five liftings during the period, resulting in sales of 2,040,792 bbls (H1 2020: 1,979,289 bbls, five liftings). Revenue The Group generated US$138.2 million of revenue in H1 2021, compared to US$115.7 million for the same period in 2020, an increase of 19%. The increase in revenue was predominately due to: �� Higher average realised prices in H1 2021, compared to H1 2020 (US$67.70/bbl vs US$46.47/bbl), contributing an additional US$41.8 million; �� A 3% increase in lifted volumes in H1 2021, compared to H1 2020, generating additional revenue of US$4.2 million; and �� Hedging income was nil1 in H1 2021, a decline of US$23.7 million compared to H1 2020. The Group's two-year capped swap cashflow hedge programme ran through to 30 September 2020. Production costs Production costs in H1 2021 were US$62.5 million (H1 2020: US$44.5 million), an increase of US$18.0 million compared to H1 2020, predominately due to: �� An additional US$8.8 million of net movement in closing crude inventories of 448kbbls, due to liftings exceeding production between the comparable periods; �� Operational staff costs were higher by US$2.0 million, due to additional contractors recruited to support repair and maintenance activities and unfavorable foreign exchange movements in non-US$ salaries; �� Repair and maintenance ("R&M") costs increased by US$2.2 million compared to H1 2020, due to additional spending on fabrication and inspection activities on both Stag and Montara; �� Workover costs were higher by US$4.4 million, due to limited activity in 2020 in response to COVID-19 impacts on oil prices and restrictions in crew movements. The Group resumed its workover campaigns at Stag during H2 2020, with more workovers and well interventions activities in the first half of 2021 compared to H1 2020; and �� Transportation costs of US$0.5 million (H1 2020: nil) following the change in offtake arrangements at Stag. The termination of the Dampier Spirit FSO lease resulted in estimated cash savings of US$3.7 million during H1 2021. 1 The hedging loss in H1 2021 of US$4.6 million was recognised as other expenses, as opposed to offsetting against revenue, due to the adoption of a different accounting treatment for the H1 2021 commodity swap contracts. The two-year capped swap programme was characterised as cashflow hedges under IFRS9 Financial Instruments and realised gains recognised as part of revenue. Losses realised on the H1 2021 swaps have been recognised in other expenses, pursuant to the characterisation of the ad hoc H1 2021 six-month swap programme as derivative instruments measured at fair value through profit or loss. The H1 2021 programme covered a short time span (not exceeding a half yearly reporting period), whereas the capped swap programme crossed three annual reporting periods. Unit operating costs per barrel were US$28.16 (H1 2020: US$23.27/bbl) before workovers, an increase on H1 2020, predominately due to lower production as a result of natural field decline production, coupled with higher operational staff costs and R&M costs as explained above. DD&A, other operating expenses and income DD&A charges in H1 2021 were US$39.7 million, versus H1 2020 of US$39.2 million, reflecting the slightly higher lifted volumes. The DD&A on a unit basis for oil and gas properties remained consistent with prior periods, while depreciation for right-of-use assets reduced primarily as a result of the September 2020 termination of the Dampier Spirit leased FSO at Stag. Other expenses in H1 2021 were US$12.5 million (H1 2020: US$16.6 million), including the fair value loss on commodity swaps of US$4.6 million, and several one-off expenses including costs associated with the acquisition of SapuraOMV's interests in Peninsular Malaysia of US$0.8 million, business development related expenses of US$1.3 million, COVID-19 related expenses of US$0.7 million, and costs associated with the corporate reorganisation of US$1.1 million. In comparison, other expenses in H1 2020 mainly comprised litigation expenses of US$8.8 million in relation to the SC56 arbitration with Total, rig contract deferral costs in Australia of US$3.0 million, and seismic acquisition costs incurred at Montara of US$1.0 million. H1 2021 other income totalled US$3.7 million (H1 2020: US$15.4 million), arising from rebate income of US$2.7 million, generated from the sublease of right-of-use assets under the Group's helicopter lease contract, and foreign exchange gains of US$1.0 million. In comparison, other income in H1 2020 included US$11.1 million awarded to the Group, for the breach of the SC56 farm out agreement by Total, and fair value gain on capped swaps of US$2.1 million. Taxation The overall net tax expense of US$8.7 million (H1 2020: US$7.4 million) comprises current income tax expense of US$8.9 million (H1 2020: US$10.5 million), reduced by a deferred tax credit of US$0.2 million (H1 2020: US$3.1 million). Current income tax expense of US$8.9 million (H1 2020: US$10.5 million) consists of corporate income tax of US$11.4 million, offset by a PRRT tax credit of US$2.5 million, with a PRRT refund received in August, as annual deductible cash payments exceeded assessable cash receipts. The deferred tax credit of US$0.2 million (H1 2020: US$3.1 million) has arisen from timing differences between the tax and accounting treatment of depreciation for oil and gas properties. H1 2021 RECONCILIATION OF CASH USD'000 USD'000 Cash and cash equivalents, 31 December 2020 80,996 Restricted cash, 31 December 2020 8,445 Total cash and cash equivalent, 31 December 2020 89,441 Revenue 138,158 Other operating income 2,908 Operating costs (62,492) Staff costs (11,427) General and administrative expenses (12,771) Cash flows from operations 54,376 Movement in working capital (53,254)1 Tax paid (8,004) Interest paid (768) Purchases of intangible exploration assets, oil and gas properties, and plant and equipment2 (15,865) Other investing activities 38 Financing activities (17,673) Total cash and cash equivalent, 30 June 2021 48,2911 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 (opex/bbl), adjusted EBITDAX, outstanding debt, and net cash. The following notes describe why the Group has selected these non-IFRS measures. 1 Total cash does not include a June lifting at Montara for US$46.1 million, the proceeds of which were received in July 2021. There were no December 2020 liftings/no outstanding trade receivable from a lifting at the December 2020 year end. The receivable from the June lifting is reflected in trade receivables as at 30 June 2021. 2 Total capital expenditure was US$16.2 million, comprising total capital expenditure paid of US$15.9 million, plus accrued capital expenditure of US$0.3 million. Operating costs per barrel (Opex/bbl) Opex/bbl 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/bbl is defined as total production costs excluding oil inventories movement, write down of inventories, workovers (to facilitate better comparability period to period) and non-recurring repair and maintenance. It also includes lease payments related to operational activities, net of any income earned from right-of-use assets involved in production, and foreign exchange gains arising from foreign exchange forwards in respect of local currency operating expenditure, and excludes depletion, depreciation and amortisation and short term COVID-19 subsidies. Adjusted aggregate production cost is then divided by total produced barrels for the prevailing period, to determine the unit cost per barrel. Six months ended Six months ended Twelve months ended USD'000 except where indicated 30 June 2021 30 June 2020 31 December 2020 Production costs (reported) 62,492 44,466 105,338 Adjustments Lease payments related to operating activities1 6,444 10,005 17,548 Movement in oil inventories2 (5,642) 3,204 2,806 Workover costs3 (10,027) (5,675) (21,686) Write down of oil inventories4 - (695) - Impact from foreign exchange derivatives apportioned to production costs5 - - (2,649) Other income6 (2,286) - (3,634) Non-recurring repair and maintenance7 - - (1,619) Transportation costs (541) - - Australian Government JobKeeper scheme 196 - 600 Adjusted production costs 50,636 51,305 96,704 Total production, barrels 1,797,989 2,205,042 4,186,478 Operating costs per barrel 28.16 23.27 23.10 1 Lease payments related to operating activities are lease payments considered to be operating costs in nature, including leased helicopters for transporting offshore crews, and the Dampier Spirit FSO rental fees prior to the lease termination in September 2020. The lease payments are added back to reflect the true cost of production. 2 Movement in oil inventories are added back to the calculation to match the full cost of production with the associated production volumes. 3 Workover costs are excluded from opex/bbl so as to enhance comparability. The frequency of workovers can vary significantly, across reporting periods, particularly at Stag. 4 Write down of oil inventories in H1 2020 is a non-cash adjustment based on the requirements of IAS 2 Inventories to reflect the closing inventories being recorded at the lower of cost or net realisable value. It is not considered a production cost. 5 A portion of the net impact from foreign exchange hedging instruments in 2020 was apportioned to production costs, based on the Group's actual local currency expenditure during the hedging period. 6 Other income represents the rental income from a helicopter rental contract (a right-of-use asset) to a third party. 7 Non-recurring repair and maintenance costs in 2020 relates to costs associated with Cyclone Damien. 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 and exploration. The calculations of adjusted EBITDAX are as follow: Six months ended Six months ended Twelve months ended USD'000 30 June 2021 30 June 2020 31 December 2020 Revenue 138,158 115,669 217,938 Production costs (62,492) (44,466) (105,338) Staff costs (12,067) (11,425) (21,903) Impairment of assets - - (50,455) Other expenses (12,501) (16,642) (26,918) Other income, excluding interest income 3,643 11,075 26,119 Other financial gains - 359 359 Unadjusted EBITDAX 54,741 54,570 39,802 Non-recurring Net loss/(gain) from oil price derivatives 4,633 (23,695) (30,889) Impairment of assets - - 50,455 Non-recurring opex1 1,574 3,311 8,270 Net litigation income - (2,295) (3,005) Rig contract deferred costs - 3,000 3,000 Gain on contingent consideration - (359) (359) Gain from termination of FSO lease - - (6,429) Others2 4,231 2,074 1,737 10,438 (17,964) 22,780 Adjusted EBITDAX 65,179 36,606 62,582 1 Includes one-off major maintenance/well intervention activities, in particular the workover campaigns at Skua 10, Skua 11 during H1 2021 and H3 in 2020, as well as other non-recurring production expenditures such as the repair and maintenance costs associated with weather downtime in 2020. 2 Includes Maari transition team costs, Australian Government JobKeeper scheme, business development and corporate re-organisation costs, as well as Montara seismic acquisition costs associated with the non-licence area and gain on contingent consideration in 2020. Outstanding debt Total borrowings, as recorded in the Group's consolidated statement of financial position, represents the carrying amount of the Group's interest bearing financial indebtedness, measured at amortised cost pursuant to IFRS 9 Financial Instruments. Outstanding debt is a non-IFRS measure which does not have a standardised meaning prescribed by IFRS. Management uses this measure to manage the capital structure, and make adjustments to it, based on the funds available to the Group. Outstanding debt is defined as long and short-term interest bearing debt, with effective interest method financing costs added back (i.e. excluded), and excluding derivatives. As at 30 June 2021, the Group has no outstanding interest bearing financial indebtedness of any kind, following the final scheduled repayment of the 2018 reserves based loan at the end of Q1 2021. USD'000 30 June 2021 30 June 2020 31 December 2020 Short term borrowing - 25,053 7,296 Add back: effective interest method financing costs - 521 90 Outstanding debt - 25,574 7,386 Net cash Net cash is a non-IFRS measure which does not have a standardised meaning prescribed by IFRS. Management uses this measure to analyse the financial strength of the Group. 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 2021 30 June 2020 31 December 2020 Outstanding debt - (25,574) (7,386) Cash and cash equivalents 47,291 95,457 80,996 Restricted cash 1,000 8,398 8,445 Net cash 48,291 78,281 82,055 Net cash is defined as the sum of cash and cash equivalents less outstanding debt. Net cash as at 30 June 2021 excludes a Montara June lifting of US$46.1 million, the proceeds of which were received in July 2021 (by comparison, there were no Montara or Stag liftings in December 2020 or June 2020). The net cash as at 30 June 2020 included the minimum working capital balance of US$15.0 million required under the Group's RBL, and restricted cash of US$8.4 million in the RBL debt service reserve account, less outstanding debt. The restricted cash of US$1.0 million as at 30 June 2021 represents a cash collateralised bank guarantee placed with the Indonesian regulator with respect to a joint study agreement entered into by the Group in Indonesia. The bank guarantee was released in August 2021. 2021 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 facing the Group as at 30 June 2021 remain unchanged from the risks disclosed in the 2020 Annual Report pages 32 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 12 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 Dan Young Executive Director Executive Director President & Chief Executive Officer Chief Financial Officer 9 September 2021 9 September 2021 Cautionary statements This announcement may contain certain forward-looking statements with respect to the Company's expectations and plans, strategy, management's objectives, future performance, production, reserves, costs, revenues and other trend information. These statements are made by the Company in good faith based on the information available at the time of this announcement, but such statements should be treated with caution due to inherent risks and uncertainties. These statements and forecasts involve risk and uncertainty because they relate to events and depend upon circumstances that may occur in the future. There are a number of factors which could cause actual results or developments to differ materially from those expressed or implied by these forward-looking statements and forecasts. The statements have been made with reference to forecast price changes, economic conditions and the current regulatory environment. Nothing in this announcement should be construed as a profit forecast. Past share performance cannot be relied upon as a guide to future performance. The Company does not assume any obligation to publicly update the information, except as may be required pursuant to applicable laws. The oil, natural gas and natural gas liquids information in this announcement has been prepared in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. A barrel of oil equivalent ("boe") is determined by converting a volume of natural gas to barrels using the ratio of six thousand cubic feet ("mcf") to one barrel. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilising a conversion on a 6:1 basis may be misleading as an indication of value. 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. Henning Hoeyland 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 been involved in the energy industry for more than 19 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. Condensed Consolidated Statement of Profit or Loss and Other Comprehensive Income for the six months ended 30 June 2021 Six months ended 30 June 2021 Six months ended 30 June 2020 Twelve months ended 31 December 2020 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Consolidated statement of profit or loss Revenue 138,158 115,669 217,938 Production costs 6 (62,492) (44,466) (105,338) Depletion, depreciation and amortisation 6 (39,697) (39,230) (84,642) Staff costs (12,067) (11,425) (21,903) Other expenses 6 (12,501) (16,642) (26,918) Impairment of assets 7 - - (50,455) Other income 3,681 15,356 26,376 Finance costs 8 (3,934) (6,834) (12,655) Other financial gains - 359 359 Profit/(Loss) before tax 11,148 12,787 (57,238) Income tax expense 9 (8,653) (7,427) (2,940) Profit/(Loss) for the period/year 2,495 5,360 (60,178) Earnings/(Loss) per ordinary share Basic and diluted (US$) 10 0.01 0.01 (0.13) Consolidated statement of comprehensive Income Profit/(Loss) for the period/year 2,495 5,360 (60,178) Other comprehensive income/(loss) Items that may be reclassified subsequently to profit or loss: Gain on unrealised cash flow hedges - 26,765 26,093 Hedging gain reclassified to profit or loss - (23,697) (31,364) - 3,068 (5,271) Tax (expense)/credit relating to components of other comprehensive income/(loss) - (921) 1,583 Other comprehensive income/(loss) - 2,147 (3,688) Total comprehensive income/(loss) for the period/year 2,495 7,507 (63,866) Condensed Consolidated Statement of Financial Position as at 30 June 2021 30 June 2021 30 June 2020 31 December 2020 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Assets Non-current assets Intangible exploration assets 11 96,443 135,105 100,670 Oil and gas properties 12 303,625 347,829 317,676 Plant and equipment 12 1,584 1,680 1,652 Right-of-use assets 12 18,358 51,070 23,673 Other receivables 13 4,451 - 4,404 Restricted cash - 10,000 - Deferred tax assets 16,318 16,535 19,727 Total non-current assets 440,779 562,219 467,802 Current assets Inventories 34,812 46,399 45,361 Trade and other receivables 13 63,135 12,637 7,110 Derivative financial instruments 19 - 10,417 - Restricted cash 1,000 8,398 8,445 Cash and cash equivalents 47,291 95,457 80,996 Total current assets 146,238 173,308 141,912 Total assets 587,017 735,527 609,714 Equity and liabilities Equity Capital and reserves Share capital 14 392 466,573 466,979 Merger reserve 15 146,269 - - Share based payments reserve 25,625 24,492 24,985 Hedging reserve - 5,835 - Accumulated losses (12,710) (263,291) (331,322) Total equity 159,576 233,609 160,642 Non-current liabilities Provisions 16 290,693 283,194 288,224 Lease liabilities 9,086 33,881 13,305 Tax liabilities - - 26,896 Deferred tax liabilities 54,564 63,155 58,229 Total non-current liabilities 354,343 380,230 386,654 30 June 30 June 31 December 2021 2020 2020 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Current liabilities Borrowings 17 - 25,053 7,296 Lease liabilities 11,625 20,420 12,478 Trade and other payables 18 22,760 22,574 32,192 Provisions 16 3,091 1,705 4,558 Derivative financial instruments 19 - - 471 Tax liabilities 35,622 51,936 5,423 Total current liabilities 73,098 121,688 62,418 Total liabilities 427,441 501,918 449,072 Total equity and liabilities 587,017 735,527 609,714 Condensed Consolidated Statement of Changes in Equity as at 30 June 2021 Share based Share Merger payments Hedging Accumulated capital reserve reserve reserve losses Total USD'000 USD'000 USD'000 USD'000 USD'000 USD'000 As at 1 January 2020 466,573 - 23,857 3,688 (268,651) 225,467 Profit for the period - - - - 5,360 5,360 Other comprehensive income for the period - - - 2,147 - 2,147 Total comprehensive income for the period - - - 2,147 5,360 7,507 Share-based compensation - - 635 - - 635 As at 30 June 2020 466,573 - 24,492 5,835 (263,291) 233,609 As at 1 January 2020 466,573 - 23,857 3,688 (268,651) 225,467 Loss for the year - - - - (60,178) (60,178) Other comprehensive loss for the year - - - (3,688) - (3,688) Total comprehensive loss for the year - - - (3,688) (60,178) (63,866) Dividend paid - - - - (2,493) (2,493) Share-based compensation - - 1,128 - - 1,128 Shares issued, net of transaction costs 406 - - - - 406 Total transactions with owners, recognised directly in equity 406 - 1,128 - (2,493) (959) As at 31 December 2020 466,979 - 24,985 - (331,322) 160,642 Share based Share Merger payments Hedging Accumulated capital reserve reserve reserves losses Total USD'000 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, net of transaction costs 799 - - - - 799 Capital reduction (467,386) 146,269 - - 321,117 - Total transactions with owners, recognised directly in equity (466,587) 146,269 640 - 316,117 (3,561) As at 30 June 2021 392 146,269 25,625 - (12,710) 159,576 Condensed Consolidated Statement of Cash Flows for the six months ended 30 June 2021 Six months Six months Twelve ended ended months ended 30 June 30 June 31 December 2021 2020 2020 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Operating activities Profit/(Loss) before tax 11,148 12,787 (57,238) Adjustments for: Depletion, depreciation and amortisation 6 33,338 30,352 68,414 Depreciation of right-of-use assets 6 / 12 6,359 8,878 16,228 Other finance costs 7 3,784 5,260 10,289 Share based payments 640 635 1,128 Provision for doubtful debts 201 - - Interest expense 7 150 1,574 2,366 Unrealised foreign exchange (gain)/loss (735) - 1,495 Reversal of fair value loss on oil derivatives (471) - - Interest income (38) (251) (257) Write down of inventories - 695 - Loss on ineffective hedge recycled to profit or loss - 2 4 Fair value gain on foreign exchange forward Contracts - (2,076) - Change in Stag FSO provision - (443) (5,047) Decrease in fair value of Montara contingent Payments - (359) (359) Impairment of intangible exploration assets 7 - - 50,455 Fair value loss on oil derivatives - - 471 Inventories written off - - 173 Provision of slow moving inventories - - 143 Gain from termination of right-of-use asset - - (1,382) Operating cash flows before movements in working capital 54,376 57,054 86,883 (Increase)/Decrease in trade and other receivables (53,777) 29,646 35,560 Decrease/(Increase) in inventories 5,719 (10,234) (14,071) (Decrease)/Increase in trade and other payables (5,196) (10,163) 3,736 Cash generated from operations 1,122 66,303 112,108 Interest paid (768) (1,110) (1,542) Tax paid (8,004) (3,260) (25,969) Net cash (used in)/generated from operating activities (7,650) 61,933 84,597 Six months Six months Twelve ended ended months ended 30 June 30 June 31 December 2021 2020 2020 Unaudited Unaudited Audited Notes USD'000 USD'000 USD'000 Investing activities Net cash outflows on acquisition of Lemang PSC - - (11,959) Payment for oil and gas properties 12 (14,173) (1,750) (4,732) Payment for plant and equipment 12 (216) (106) (473) Payment for intangible exploration assets 11 (1,476) (11,129) (14,253) Transfer from debt service reserve account 7,445 5,087 5,040 Interest received 38 251 257 Net cash used in investing activities (8,382) (7,647) (26,120) Financing activities Net proceeds from issuance of shares 799 - 406 Release of deposit for bank guarantee - - 10,000 Dividends paid (5,000) - (2,493) Repayment of borrowings (7,356) (24,570) (42,766) Repayment of lease liabilities (6,116) (10,193) (18,562) Net cash used in financing activities (17,673) (34,763) (53,415) Net (decrease)/increase in cash and cash equivalents (33,705) 19,523 5,062 Cash and cash equivalents at beginning of the period/year 80,996 75,934 75,934 Cash and cash equivalents at end of the period/year 47,291 95,457 80,996 Explanation Notes to the Condensed Consolidated Interim Financial Statements for the six months ended 30 June 2021 1. GENERAL INFORMATION Jadestone Energy plc (the "Company" or "Jadestone") is an oil and gas company incorporated in England and Wales. The Company was incorporated on 22 January 2021, company registration number 13152520. The Company became the ultimate parent company on 23 April 2021, following the completion of a corporate reorganisation (see below). The Company's shares are traded on AIM under the symbol "JSE". The financial statements are expressed in United States Dollars. The Company and its subsidiaries (the "Group") are engaged in production, development, exploration and appraisal activities in Australia, Malaysia, Vietnam, Indonesia and the Philippines. The Group's producing assets during H1 2021 were in the Vulcan (Montara) and Carnarvon (Stag) basins, offshore Western Australia. 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 9 September 2021, on the recommendation of the audit committee. 2. DIVIDENDS On 11 June 2021, the directors declared a second interim 2020 dividend of 1.08 US cents/share, equivalent to 0.77 GB pence/share, based on an exchange rate of 0.7087, equivalent to a total distribution of US$5.0 million, or US$7.5 million in respect of total 2020 dividends. The dividend was paid on 30 June 2021. On 9 September 2021, the directors declared a 2021 interim dividend of 0.59 US cents/share (or equivalent to 0.43 GB pence/share based on the current spot exchange rate of 0.7257), equivalent to a total distribution of US$2.8 million. The dividend will be paid on a gross basis, in US dollars. 3. SIGNIFICANT EVENTS DURING THE PERIOD Corporate reorganisation The Company completed an internal reorganisation on 23 April 2021, with Jadestone Energy plc becoming the ultimate holding company of the Jadestone group of companies. The shares of Jadestone Energy Inc., the former ultimate holding company, have been replaced on a one-for-one basis with shares of Jadestone Energy plc. Following the completion of the internal reorganisation, Jadestone Energy plc was admitted to AIM for trading on 26 April 2021 (Jadestone Energy Inc. shares ceased trading on 23 April 2021). The internal reorganisation has not resulted in a change in control in the ultimate holding company of the Group and, accordingly, has not resulted in a change in control in the ultimate shareholding in any of the companies or assets of the Group. Further, the internal reorganisation has not resulted in a change in the management of any of the Group's companies or assets. Acquisition of SapuraOMV Peninsular Malaysia assets On 30 April 2021, the Group executed a sale and purchase agreement with SapuraOMV Upstream Sdn. Bhd. ("SapuraOMV") to acquire SapuraOMV's Peninsular Malaysia assets (the "PenMal Assets"), for a total cash consideration of US$20.0 million, which included a headline price of US$9.0 million plus further working capital adjustments of US$11.0 million, and subject to certain subsequent contingent payments related to the price of average annual Dated Brent throughout 2021 and 2022. The acquisition was completed on 1 August 2021. The economic effective date of the acquisition was 1 January 2021, meaning the Group is entitled to all net cash generated from the PenMal Assets from 1 January 2021 to 31 July 2021. As a result, at completion the Group obtained cash held by SapuraOMV Upstream (PM) Inc. of US$29.2 million, resulting in a net cash receipt of US$9.2 million for the acquisition. The PenMal Assets comprise four licences, two of which are operated by the Group. These consist of a 70% operated interest in the PM329 PSC, containing the East Piatu field, and a 60% operated interest in the PM323 PSC, which contains the East Belumut, West Belumut and Chermingat fields. The other two licences consist of 50% non-operated working interests in the PM318 and AAKBNLP PSCs. Oil price commodity contracts On 16 February 2021, the Group entered into commodity swap contracts to hedge 31% of its planned production volumes from April to June 2021, to provide downside oil price protection during the period leading into the 2021 offshore Australia capital programme. The average swap price, referenced to Dated Brent, was set at US$61.40/bbl. 4. 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 2020. 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. Common control transaction As disclosed in Note 3, the Company has completed an internal reorganisation, with the shares of Jadestone Energy Inc. having been replaced on a one-for-one basis with shares of Jadestone Energy plc. Accordingly, Jadestone Energy plc was admitted to AIM for trading on 26 April 2021. There is no change in control in the ultimate holding company of the Group arising from the completion of the internal reorganisation. IFRS 3 Business Combinations does not prescribe the presentation and disclosure requirements under common control transaction. The Group has chosen to issue these unaudited condensed consolidated interim financial statements under the name of Jadestone Energy plc, as if they are a continuation of the financial statements of Jadestone Energy Inc. and Jadestone Energy plc had been in existence throughout the reported financial period. The following have been reflected in these unaudited condensed consolidated interim financial statements in relation to the common control transaction: a) the asset and liabilities of Jadestone Energy plc and Jadestone Energy Inc. ("JEI") Group have been recognised at their book values immediately prior to the internal reorganisation; b) the pre-internal reorganisation accumulated losses recognised in these consolidated financial statements are those of JEI Group; c) the amount recognised as issued equity instruments in these consolidated financial statements is the issued and paid-up share capital share capital of JEI immediately before the internal reorganisation; d) the equity structure appearing in these consolidated financial statements (i.e. the number and type of equity instruments issued) reflects the equity structure of the Company; and e) the comparative information presented in these consolidated financial statements is that of JEI Group. GOING CONCERN The directors are satisfied that the Group has sufficient resources to continue in operation for the foreseeable future, a period of not less than 12 months from the date of this report. Accordingly, they continue to adopt the going concern basis in preparing the condensed consolidated interim financial statements. RECLASSIFICATION OF COMPARATIVE FIGURES Certain comparative figures in the unaudited financial statements of the Group for the period ended 30 June 2020 have been reclassified to conform with the audited consolidated financial statements for the year ended 31 December 2020, along with the presentation in the current period. The reclassifications made in the statement of profit or loss are mainly related to the litigation income and expenses in relation to SC56, which are now present on a gross basis under other income and other expenses, respectively. These reclassifications were made to better reflect the nature of the respective items in the Group's 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 2021. - IFRS 16 COVID-19 Related Rent Concessions amendments The amendment is effective for annual periods beginning on 1 June 2020 and generally requires prospective application. 5. 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 2020. 6. OPERATING COSTS Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2021 2020 2020 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Production costs 61,951 44,466 105,338 Transportation costs 541 - - Total production costs 62,492 44,466 105,338 Depletion and amortisation of oil and gas properties 33,054 30,146 67,813 Depreciation of plant equipment and right-of-use assets 6,643 9,084 16,829 Total depletion, depreciation and amoritisation 39,697 39,230 84,642 Corporate costs 12,230 15,506 25,471 Exploration expenses - 972 972 Other operating expenses 271 164 475 Total other expenses 12,501 16,642 26,918 7. IMPAIRMENT OF ASSETS Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2021 2020 2020 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Impairment of intangible exploration assets - - 50,455 8. FINANCE COSTS Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2021 2020 2020 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Interest expense and others 1,465 3,671 6,292 Accretion expense 2,469 3,163 6,363 3,934 6,834 12,655 9. INCOME TAX EXPENSE The Company is tax resident in Singapore and therefore is subjected to Singapore's domestic corporate tax rate of 17%. The subsidiaries are resident for tax purposes in the territories in which they operate. The current period tax charge of US$8.7 million (H1 2020: US$ 7.4 million) was generated through operations in Australia, including PRRT at 40% and a corporate tax rate of 30%. No other locations generated taxable profits. Current income tax expense of US$8.9 million (H1 2020: US$10.5 million) consists of corporate income tax expense of US$11.4 million, offset by a PRRT tax credit of US$2.5 million, with a PRRT refund received in August, as annual deductible cash payments exceeded assessable cash receipts. A deferred tax credit of US$0.2 million (H1 2020: US$3.1 million) has arisen from timing differences between the tax and accounting treatment of depreciation of oil and gas properties. 10. PROFIT PER ORDINARY SHARE The calculation of the basic and diluted profit per share is based on the following data: Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2021 2020 2020 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Profit for the purposes of basic and diluted per share, being the net profit for the period attributable to equity holders of the Company 2,495 5,360 (60,178) Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2021 2020 2020 Unaudited Unaudited Audited Number Number Number Weighted average number of ordinary shares for the purposes of basic EPS 462,894,872 461,042,811 463,553,521 Effect of dilutive potential ordinary shares - share options 6,100,692 3,990,155 - Weighted average number of ordinary shares for the purposes of diluted EPS 468,995,564 465,032,966 463,553,521 The calculation of diluted EPS for the six months ended 30 June 2021 includes 6,100,692 of weighted average dilutive ordinary shares available for exercise from in-the-money vested options (six months ended 30 June 2020: 3,990,155). Additionally, 407,842 of weighted average potential ordinary shares available for exercise, are excluded as they are out-of-the-money (six months ended 30 June 2020: 607,821). For the full year ended 31 December 2020, there were 4,679,402 of potential ordinary shares associated with share options which were anti-dilutive. Six months ended Six months ended Twelve months ended 30 June 30 June 31 December 2021 2020 2020 Earnings/(Loss) per share (US$) Unaudited Unaudited Audited - - Basic 0.01 0.01 (0.13) - - Diluted 0.01 0.01 (0.13) 11. INTANGIBLE EXPLORATION ASSETS Total USD'000 Cost As at 1 January 2020 117,440 Additions 17,665 As at 30 June 2020 135,105 Acquisition of Lemang PSC 14,825 Additions 1,195 As at 31 December 2020/1 January 2021 151,125 Additions 1,832 Reversal (6,059) Written off (50,455) As at 30 June 2021 96,443 Impairment As at 1 January 2020/30 June 2020 - Additions 50,455 As at 31 December 2020/1 January 2021 50,455 Written off (50,455) As at 30 June 2021 - Net book value As at 30 June 2020 (unaudited) 135,105 As at 31 December 2020 (audited) 100,670 As at 30 June 2021 (unaudited) 96,443 In November 2020, Jadestone and Total voluntarily surrendered their entire combined 100% interest in SC56 to the Philippines Department of Energy ("DOE"). As a result, the SC56 carrying value of US$50.4 million was impaired in Q4 2020. The DOE acknowledged the relinquishment in February 2021 and the exit obligation terms were agreed in June 2021. Accordingly, the carrying value was formally written off in Q2 2021. The US$6.0 million reversal in H1 2021 relates to an overprovision of costs owed to a third party contractor joint venture. The overprovision was identified following an assessment of actual costs incurred by the third party contractor. 12. PROPERTY, PLANT AND EQUIPMENT Oil and gas properties Plant and equipment Right-of-use assets Total USD'000 USD'000 USD'000 USD'000 Cost As at 1 January 2020 492,985 4,139 74,663 571,787 Additions 1,750 106 760 2,616 Termination - - (307) (307) Adjustment - - (394) (394) As at 30 June 2020 494,735 4,245 74,722 573,702 Changes in asset restoration obligations (725) - - (725) Additions 2,982 367 131 3,480 Termination - - (29,339) (29,339) As at 31 December 2020/ 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 Accumulated depletion, depreciation and amortisation As at 1 January 2020 111,311 2,359 14,876 128,546 Charge for the period 35,595 206 8,878 44,679 Termination - - (102) (102) As at 30 June 2020 146,906 2,565 23,652 173,123 Charge for the period 32,410 395 7,350 40,155 Termination - - (9,161) (9,161) As at 31 December 2020/ 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 Net book value As at 30 June 2020 (unaudited) 347,829 1,680 51,070 400,579 As at 31 December 2020 (audited) 317,676 1,652 23,673 343,001 As at 30 June 2021 (unaudited) 303,625 1,584 18,358 323,567 13. TRADE AND OTHER RECEIVABLES 30 June 2021 30 June 2020 31 December 2020 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Non-current VAT receivables 4,451 - 4,404 Current Trade receivables 46,291 1 106 Prepayments 6,093 2,208 2,012 Other receivables and deposits 6,621 5,759 4,273 PRRT receivables 2,496 3,883 - GST/VAT receivables 1,634 786 719 63,135 12,637 7,110 67,586 12,637 11,514 Provision for doubtful debts At beginning of period/year - - - Addition 201 - - At end of period/year 201 - - A trade receivable of US$46.1 million arising from a June 2021 Montara lifting was received in July 2021. 14. SHARE CAPITAL Authorised ordinary shares Unlimited number of ordinary voting shares with par value of at ��0.001. No. of shares USD'000 Issued and fully paid As at 1 January 2020/30 June 2020 461,042,811 466,573 Issued during the period 800,000 406 As at 31 December 2020/1 January 2021 461,842,811 466,979 Issued during the period 1,856,666 799 Capital reduction, at ��0.499 each - (467,386) As at 30 June 2021 463,699,477 392 On 4 May 2021, the High Court of Justice, Business and Property Court, Companies Court in England and Wales approved the reduction of share capital of the Company pursuant to section 648 of the Act by cancelling the paid up capital of the Company to the extent of 49.9 pence on each ordinary share of ��0.50 in the issued share capital of the Company. The effective date of the capital reduction was 6 May 2021. In the six months ended 30 June 2021, the Group granted to its employees 2.9 million of share options, 1.1 million of performance shares and 0.1 million of restricted share units (H1 2020: 6.5 million of share options; 0.6 million of performance shares and 0.1 million of restricted share units) in respect of achievement of 2020 performance objectives. 15. 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 (Note 3 and 4). 16. PROVISIONS 30 June 2021 30 June 2020 31 December 2020 Unaudited Unaudited Audited USD'000 USD'000 USD'000 Non-current Asset restoration obligations 286,219 278,543 283,750 Others 4,474 4,651 4,474 290,693 283,194 288,224 Current Others 3,091 1,705 4,558 293,784 284,899 292,782 17. BORROWINGS 30 June 2021 Unaudited USD'000 30 June 2020 Unaudited USD'000 31 December 2020 Audited USD'000 Current secured borrowings Reserves based lending facility - 25,053 7,296 18. TRADE AND OTHER PAYABLES 30 June 2021 Unaudited USD'000 30 June 2020 Unaudited USD'000 31 December 2020 Audited USD'000 Trade payables 3,377 6,325 10,131 Other payables 1,662 84 2,004 Accruals 17,714 16,126 20,047 GST/VAT payables 7 39 10 22,760 22,574 32,192 19. DERIVATIVE FINANCIAL INSTRUMENTS 30 June 2021 Unaudited USD'000 30 June 2020 Unaudited USD'000 31 December 2020 Audited USD'000 Derivative financial assets/(liabilities) Designated as cash flow hedges Commodity capped swap - 8,341 - Carried at fair value though profit or loss Commodity swap - 2,076 (471) The fair values of the commodity swap were classified as Level 2 and calculated using market prices that the Group would pay or receive to settle those swap contracts. 20. 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 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 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) 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 Six months ended 30 June 2020 (unaudited) Revenue Liquids revenue 91,970 - - 91,970 Hedging income 23,699 - - 23,699 115,669 - - 115,669 Production costs (44,466) - - (44,466) DD&A (39,036) (56) (138) (39,230) Staff costs (5,965) (907) (4,553) (11,425) Other expenses (5,055) (8,895) (2,692) (16,642) Other income 4,269 11,087 - 15,356 Finance costs (6,823) (1) (10) (6,834) Other financial gains 359 - - 359 Profit/(Loss) before tax 18,952 1,228 (7,393) 12,787 Additions to non-current assets 7,576 12,288 417 20,281 Non-current assets 416,276 128,394 1,014 545,684 Producing assets Exploration/ Development Australia USD'000 SEA USD'000 Corporate USD'000 Total USD'000 Twelve months ended 31 December 2020 (audited) Revenue Liquids revenue 186,572 - - 186,572 Hedging income 31,366 - - 31,366 217,938 - - 217,938 Production costs (105,338) - - (105,338) DD&A (84,024) (110) (508) (84,642) Staff costs (10,029) (2,228) (9,646) (21,903) Other expenses (15,068) (9,690) (2,160) (26,918) Impairment of assets - (50,455) - (50,455) Other income 14,292 12,084 - 26,376 Finance costs (12,625) (29) (1) (12,655) Other financial gains 359 - - 359 Profit/(Loss) before tax 5,505 (50,428) (12,315) (57,238) Additions to non-current assets 11,162 27,706 914 39,782 Non-current assets 349,292 97,838 945 448,075 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. 21. EVENT AFTER THE REPORTING PERIOD Completion of acquisition of SapuraOMV Peninsular Malaysia assets On 1 August 2021, all conditions precedent to closing the acquisition of the SapuraOMV Peninsular Malaysia assets were satisfied and the Group proceeded to close the acquisition, including the transfer of operatorship of PM329 PSC and PM323 PSC. Glossary �� British pound sterling 2P the sum of proved and probable reserves, reflecting those reserves with 50% probability of quantities actually recovered being equal or greater to the sum of estimated proved plus probable reserves 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 bscf billion standard cubic feet equivalent Btu British thermal unit Btu/d British thermal unit per day BBtu/d Billion Btu/d capex capital expenditures CIF used here to characterise the shipping arrangement typically negotiated for Stag post termination of Dampier Spirit FSO, whereby charges such as cost, insurance and freight are paid by Jadestone while the crude oil is in transit to the buyer DD&A depletion, depreciation and amortisation EBITDAX earnings before interest tax, depreciation, amortisation and exploration EPS earnings per share FOB used here to characterise the shipping arrangement typically negotiated for Montara liftings, and for Stag liftings during the period when the Dampier Spirit FSO was in place, under which liftings were agreed on a free-on-board basis at the offtake hose of the FPSO (Montara)/FSO (Stag) FPSO floating production storage and offloading FSO floating storage and offloading GB pence, GBp Great Britain pence GHG greenhouse gases GST goods and services tax IFRS International Financial Reporting Standards JEI Jadestone Energy Inc. mm million mmBtu million British thermal unit opex operating expenditures PRRT Petroleum Resource Rent Tax PSC production sharing contract RBL reserves based loan reserves hydrocarbon resource that is anticipated to be commercially recovered from known accumulations from a given date forward SEA Southeast Asia US$ or USD United States dollar VAT value-added tax This information is provided by RNS, the news service of the London Stock Exchange. 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