Jadestone Energy Regulatory News (JSE)

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

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

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 ResultsStart time: 9:00 a.m. (London)/4:00 p.m. (Singapore)Date: Thursday, 9 September 2021Conference ID: 24719928

Dial-in number details:

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.

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

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.

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:

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.

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.

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

Condensed Consolidated Statement of Financial Position as at 30 June 2021

Condensed Consolidated Statement of Changes in Equity as at 30 June 2021

Condensed Consolidated Statement of Cash Flows for the six months ended 30 June 2021