The following amendment has been made to the 2022 Preliminary Unaudited Full Year Results announcement released on 25 April at 7:00 under RNS No 3517X.

It changes 2023 production guidance to read:

·    Production for the nine months ending 31 December 2023 is expected to average 13,500-17,000 boe/d.

All other details remain unchanged.

The full amended text is shown below.

2022 Preliminary Unaudited Full Year Results

25 April 2023-Singapore: Jadestone Energy plc (AIM:JSE) ("Jadestone" or the "Company"), an independent oil and gas production company and its subsidiaries (the "Group"), focused on the Asia-Pacific region, reports today its preliminary¹ unaudited consolidated financial statements (the "Financial Statements"), as at and for the financial year ended 31 December 2022.  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:

"2022 was an extremely frustrating year operationally, one which largely overshadowed the underlying progress made in a number of key strategic areas.  The first half of the year validated our strategy at work, as we generated significant operating cash flow, building our cash balance to a record high of US$162 million by mid-year.  The second half however highlighted the over-reliance on Montara for operational and financial performance, highlighting that we are vulnerable to single events on this asset.

Since we became operator of Montara in 2019, we have been undertaking an ongoing programme to revitalise the asset through a systematic process of inspection, remediation and repair.  Progress has been impacted by COVID-related manning restrictions over the past 18 months, that caused delays to this programme, and which frustratingly contributed to the unplanned event in July when a small hole in storage tank 2C was detected, a tank that was scheduled to be next in the inspection programme.

We have since undertaken an extensive 8-month shutdown, which has allowed us to address required regulatory actions, and carried out a detailed inspection of critical areas of the FPSO and the necessary repairs and maintenance to restart production.  This was the right thing to do notwithstanding the major short-term impact on the business, and our clear focus from now on is to ensure to the best of our ability that there will be no further unplanned events of this nature at Montara.  Since restarting production in March 2023,  Montara has performed in line with expectations, producing from three wells at c.4,700 bbls/d, with additional wells becoming available for production in the coming weeks and more cargo tanks being returned to service in due course.

Over the past eight months, Montara has stress tested our resilience, and I am very proud of the way in which the whole team has responded in these difficult circumstances to work through the issues and bring the asset back on stream. 

However, the past 8 months, although challenging, has also demonstrated that we have the right strategy, highly cash generative with quick pay-back, adding to our production portfolio in a disciplined way.  In doing this, we are repositioning the portfolio to ensure this won't be repeated, so while Montara was 80% of our production in mid-2021, it is expected to be 20% of our production by mid-2024.  Over the same period, we will have expanded the business from just two producing assets to seven in multiple countries and jurisdictions, providing the portfolio diversity that will insulate the company from the impact of such events in the future, a benefit usually exclusive to the majors and one that will differentiate us from our peers.

Despite the hiatus at Montara, our robust business model allowed us to end 2022 with an increased cash balance over the 12-month period and a US$9 million profit for the year.  This was delivered against a backdrop of an extensive capital programme, a share buy-back of approximately US$18 million, completion of two acquisitions including BP's interest in the highly attractive CWLH assets on the North West shelf, and commencement of the Akatara gas field development, our largest ever organic project, onshore Indonesia. 

Due to a combination of first quarter 2023 liftings being back-end loaded and high activity levels throughout our portfolio, cash available by end March 2023 had reduced to US$64 million, with US$29m of debt drawn from the Interim Facility to fund the Sinphuhorm acquisition.

With respect to the RBL, we have one international bank credit approved and three others in the credit approval process, and expect the facility to close in May 2023 once customary conditions precedent are satisfied.  We also anticipate approval from NOPTA on the CWLH title transfer to Jadestone in May, which is required to draw down the RBL.  The RBL would restore our capital flexibility and even though we maintain a high level of reinvestment in the business, the highly cash generative nature of our portfolio, particularly after Akatara comes onstream, should see us approaching a net cash position around the end of 2024 based on expected operating performance and current oil prices.  Importantly, the RBL will also facilitate the funding of further acquisitions of producing assets.  Our intention as previously, will be to utilise some hedging to help secure the RBL repayment schedule, while still retaining a significant exposure to oil price upside.  In line with our approach to the final 2021 dividend, a recommendation on the final dividend for 2022 will be made when our audited accounts are released in late-May 2023.

In addition to the recently acquired gas production at Sinphuhorm, we will add the fixed price gas that is expected onstream at Akatara in the first half of next year, both of which give increased reliability to future cash flows. 

Strong growth in the business is emphasised by the 45% increase in 2P reserves at year-end, circa six times production replacement, and it is worth recognising, that we have maintained asset reserves at Montara, reinforcing the principle that despite the shut-down, reserves and cash flows have been deferred and not lost.  This provides a lot of encouragement for the future; our company has been proven to be resilient through the challenges we have faced and we have strengthened the business through both product and portfolio diversification, a strategy we will continue to pursue.

2023 should be a promising year for Jadestone with the Akatara project in the Lemang PSC on schedule and within budget, an exciting four well programme at East Belumut, closing of Sinphuhorm and the potential to add to the portfolio through further acquisitions.  

I'm extremely grateful to the people within Jadestone who have worked tirelessly across the business to get us back on track, and despite a period of significant challenge imposed by the events of the past several months, have never wavered from doing the right thing.  It has been a challenging year, lessons have been learned and implemented, but we look forward with renewed confidence to the future"

Paul Blakeley

EXECUTIVE DIRECTOR, PRESIDENT AND CHIEF EXECUTIVE OFFICER

¹ The audited financial results will be released on 25 May 2023 together with the release of the Group's FY2022 Annual Report.

2022 SUMMARY

Operational and financial summary

·    Proven and probable reserves at year-end 2022 totalled 64.8 mmboe, a 45% increase compared to the reserves at year-end 2021 of 44.7 mmbbls, representing a reserves replacement of 579%, reflecting the conversion of Akatara gas field contingent resources to reserves and addition of the non-operating working interest in the Cossack, Wanaea, Lambert and Hermes ("CWLH") Assets, offset by production and modest technical revisions during the year;

·    Full year production decreased by 8% to 11,487 boe/d (2021: 12,545 bbls/d), due to Montara being shut-in for tank repairs from August 2022 and the FPSO class suspension at the non-operated Peninsular Malaysia ("PenMal") Assets.  This was offset by higher annualised production at the operated PenMal Assets due to a full year of operations in 2022 and two months' contribution from the CWLH Assets;

·    Total lifted volumes in 2022 decreased 7% to 4.3 mmboe (included lifted volumes of 0.7 mmbbls from the CWLH Assets), compared to 4.7 mmboe in 2021, reflecting lower production at Montara and the non-operated PenMal Assets;

·    Total revenue increased 24% to US$421.6 million (2021: US$340.2 million) due to a 40% increase in realised prices, partly offset by a 7% reduction in lifted volumes;

·    The average realised price for the year was US$103.85/bbl in 2022 (2021: US$74.34/bbl), a 40% increase year-on-year.  The average realised price premium was US$7.81/bbl for 2022 (2021: US$3.39/bbl);

·    Total production costs of US$250.7 million, compared to US$211.9 million in 2021, due to:

o  The inclusion of US$37.8 million in 2022 associated with the CWLH Assets acquired in November 2022, consisting of US$3.7 million cash operating costs and an additional US$34.1 million of non-cash inventory movements, relating to moving from a significant underlift position to an overlift position following the lifting which occurred in mid-November 2022;

o  A full year of operations and supplementary payments at the PenMal Assets following their acquisition in August 2021, whereby the supplementary payment also increased due to higher realised oil prices;

o  Reduced production costs at Montara reflecting the shut-in from August 2022 through the end of 2022; and

o  Lower Stag production costs due to reduced workover activities in 2022 compared to the previous year.

·    In line with previous disclosures, adjusted annualised unit operating costs² for 2022 were US$37.49/boe, compared to US$26.22/bbl in 2021, primarily due to the lower production from Montara and the non-operated PenMal Assets;

·    Adjusted EBITDAX increased by 14% to US$161.9 million compared to US$142.2 million in 2021, predominately due to higher oil prices driving higher revenues party offset by lower adjustments for one-off expenditures;

·    Net profit after tax of US$8.5 million (2021: US$17.1 million loss after tax);

·    Operating cash flow generation in 2022 of US$158.1 million, before movements in working capital, up 73% compared to 2021 of US$91.2 million;

·    Capital expenditure of US$82.9 million (2021: US$56.0 million), a 48% increase from 2021, primarily due to the Stag infill drilling programme completed in 2022 and the Akatara gas development at the Lemang PSC.  The administration expenses related to the Lemang PSC are accounted for as operating expenditures (as Administrative Staff Costs and Other Expenses) of approximately US$2.0 million in 2022;

·    Cash balances of US$123.3 million at 2022-year end, 5% higher compared to 2021 at US$117.9 million.

·    The share buyback programme acquired 18.2 million shares in 2022, at an average cost of US$0.88 (0.76 GBp) per share for a total cost of US$16.2 million; and

·    On 20 September 2022, the Directors declared a 2022 interim dividend of 0.65 US cents/share, equivalent to a total distribution of US$3.0 million.  In line with the approach taken in respect of the final 2021 dividend in June 2022, a recommendation on the final dividend for 2022 will be made when the Group's audited accounts are released in late-May 2023.

Business development

·    On 6 June 2022, the Group took the final investment decision to develop the Akatara gas field, onshore Indonesia, with project completion and first gas scheduled in the first half of 2024;

·    On 27 October 2022, the Group announced the termination of the Maari acquisition due to a lack of progress on regulatory approvals and resultant uncertainty over the timing for the transfer of interest and operatorship;

·    On 28 July 2022, the Group executed a sale and purchase agreement with BP Developments Australia Pty Ltd ("BP") to acquire BP's non-operated 16.67% working interest in the CWLH oil field development, offshore Western Australia; and

·    On 24 November 2021, the Group executed a settlement and transfer agreement with PT Hexindo Gemilang Jaya ("Hexindo") to acquire the remaining 10% interest in the Lemang PSC.

Significant and subsequent events

·    On 7 February 2022, the Bunga Kertas FPSO, deployed at the non-operated PenMal Assets, had its class suspended, resulting in operations being shut-in and production suspended.  Jadestone has assumed operatorship of the non-operated licences following the decision of the previous operator to withdraw.  Jadestone looks forward to evaluating redevelopment options for the fields;

·    On 17 June 2022, the Montara FPSO released between three to five cubic metres of crude oil to sea during a routine oil transfer between storage tanks.  As a precaution, production was shut in and the relevant authorities were notified.  Following a temporary repair and isolation of the tank where the leak originated, production restarted while a permanent repair was developed.  On 12 August 2022, an additional defect was identified in a ballast water tank, after which the Group took the decision to shut in production and prioritise permanent repairs.  In response to the new defect, the regulator issued a General Direction requiring an independent assessment of the storage tanks before restarting production.  Following the submission of the independent review of the Group's remediation plans and operational readiness for the Montara Venture FPSO on 8 February 2023, the local regulator lifted the General Direction on 27 February 2023 and Montara production resumed on 21 March 2023;

·    On 19 January 2023, the Group executed a sale and purchase agreement with Salamander Energy (S.E. Asia) Limited (the "Seller"), an affiliate of PT Medco Energi Internasional Tbk to acquire the Seller's interest in three legal entities, which collectively own a 9.52% non-operated interest in the producing Sinphuhorm gas field and a 27.2% interest in the Dong Mun gas discovery onshore northeast Thailand; and

·    On 17 February 2023, the Group closed a US$50.0 million debt facility ("Interim Facility") with two international banks.  The closing of the Interim Facility forms part of the previously announced plan to arrange a reserves-based lending facility ("RBL"), which is a key element of the Group's medium-term financing strategy to fund development capital at the Indonesian Akatara Gas Project and enable further inorganic growth of the Group.  US$28.5 million of the Interim Facility was drawn to fund the acquisition of a 9.52% interest in the Sinphuhorm gas field, with Group cash balances of US$63.9 million as at 31 March 2023.  The Group continues to make good progress on the RBL workstreams, with one international bank credit approved and three others in the credit approval process, with signing of the RBL facility agreement targeted for May 2023.  Once signed, the RBL is expected to close shortly thereafter once all customary conditions precedent are satisfied.  It is expected that approval from the National Offshore Petroleum Titles Administrator ("NOPTA") of the transfer of titles relating to the acquisition for the CWLH fields interest will be required prior to drawing down the RBL.

2023 Guidance

·    Production for the first three months of 2023 averaged just over 10,000 boe/d, reflecting tank repair and scheduled maintenance activities at Montara.  Production for the nine months ending 31 December 2023 is expected to average 13,500-17,000 boe/d;

·    Underlying operating costs in 2023 are expected to total US$180.0-210.0 million.  When adjusted for a full-year of operating costs associated with the CWLH Assets acquisition, higher tanker costs at Stag and higher logistics costs at Montara in 2023, underlying operating costs are expected to be c.6% higher year-on-year, demonstrating cost control in an inflationary environment; and

·    Capital expenditure guidance for 2023 is expected to total US$110.0-140.0 million, the largest investment programme in the Group's history.  This is allocated primarily to the Akatara gas development project (c.70%), which is progressing well and remains on budget and schedule for first gas in H1 2024.  A further 15% will be spent on the PM323 PSC infill drilling campaign offshore Malaysia.

¹ Realised oil price represents the actual selling price inclusive of premiums.

² Operating costs per boe, adjusted EBITDAX and net cash are non-IFRS measures and are explained in further detail on the Non-IFRS Measures section in this document.

Conference call and webcast

The Company will host an investor and analyst conference call at 9:00 a.m. (London), 4:00 p.m. (Singapore) on Tuesday, 25 April 2023, including a question and answer session.

A live webcast of the presentation will be available at the link below.  Dial-in details are also provided below.  Please register approximately 15 minutes prior to the start of the call. 

Webcast link: https://app.webinar.net/ZOKNWg2PypR

Event title: Jadestone Energy Full-Year 2022 Results

Time: 9:00 a.m. (UK time) / 4:00 p.m. (Singapore time)

Date: 25 April 2023

Conference ID: 61840872

To join the conference call by phone, please use the following link to register and be connected into the conference call automatically:

https://emportal.ink/3Z9UDjQ

Participants can also join the call via an operator through the numbers below.

ENVIRONMENT, SOCIAL AND GOVERNANCE ("ESG")

As a responsible upstream operator, Jadestone contributes to an orderly energy transition by helping to meet regional Asia-Pacific energy demand whilst minimising the environmental footprint of its operations and committing to climate mitigation targets.  In doing so, Jadestone aims to bring positive social and economic benefits for its stakeholders, local communities and people associated with its operations.

Jadestone believes that its strategy of acquiring and maximising the life of mid-life producing fields and the development of existing gas discoveries is consistent with the key findings of the IEA's Net Zero by 2050 Roadmap, stating that "there is no need for investment in new fossil fuel supply in the (IEA's) net zero pathway".  The Group is well positioned to play its role in the energy transition as a responsible steward of mid-life assets divested by larger companies, committed to upholding climate targets as it continues to execute its Net Zero by 2040 strategy.

HSE performance

The Group's priority remains the health and safety of its staff, contractors and communities in which we operate, along with ensuring that any negative environmental impacts from operations are minimised. 

Health and safety performance improved in 2022 with the total recordable injury frequency rate (TRIFR) at 2.86, working over 1.7 million work hours.  There were four recordable injuries in 2022, with all individuals returning to work the same day.  There was one lost time injury, incurred at Stag, from which the individual made a full recovery.  A detailed investigation was completed and ensuing actions and engineering modifications fully implemented to prevent a reoccurrence.

Overall, the Group has had no major events resulting in significant environmental impact.

At the Akatara gas development within the Lemang PSC in Indonesia, work commenced to prepare the site for construction of the gas plant following final investment decision in June 2022.  Jadestone has worked with the EPCI contractor to ensure that robust HSE management practices are implemented and monitored.  The project worked consumed 0.6 million manhours in 2022 without a recordable injury.  This represents an excellent performance as various ongoing work included high-risk activities such as pile driving, earth moving and general construction works.  Visits to site are performed by Jadestone and the EPCI contractor's management teams on a monthly basis, a key focus area being HSE performance and regular monitoring through conducting site walk downs. 

As referenced previously, on 18 June 2022, between three to five cubic metres of crude oil was released to sea during a routine oil transfer between tanks on the Montara Venture FPSO in Australia.  The leak was successfully stopped within ten minutes and the Australian offshore energy regulator, NOPSEMA, was notified.  The released oil had naturally dispersed in full by the morning of 19 June 2022.  NOPSEMA subsequently issued a Prohibition Notice on 20 June 2022 requiring Jadestone to assess the fitness for service of all tanks capable of holding petroleum and undertake any appropriate remediation works prior to loading into that tank.

Production operations resumed in July 2022 but were then shut in again in August 2022 after an additional defect was identified in a ballast water tank in the Montara Venture FPSO.  NOPSEMA issued a General Direction to Jadestone on 12 September 2022 requiring an independent third-party undertake a management system gap analysis, review and provide advice on remediation plans developed by Jadestone, and confirm operational readiness of the facility before restart could commence.  This work was subsequently completed.  The General Direction was lifted on 8 February 2023, followed by a restart programme that commenced on 23 March 2023.

GHG emissions and Net Zero commitment

In 2022, direct Scope 1 and 2 GHG emissions, which include the Malaysia operated assets following the PenMal Assets acquisition in 2021, amounted to 488,951 tonnes CO_2-e.  When compared to full year 2021 Scope 1 and 2 GHG emissions (including the period before completion of the PenMal Assets acquisition), the Group's absolute direct Scope 1 and 2 GHG emissions were c.25% lower in 2022, largely due to the suspension of Montara operations discussed above.

In June 2022, the Group pledged to achieve Net Zero Scope 1 and 2 GHG emissions from its operated assets by no later than 2040.  The detail of this commitment can be viewed on Jadestone's website¹.

Jadestone has partnered with a reputable third-party to:

-       Establish its GHG accounting and target-setting methodology in alignment with best practice

-       Develop a GHG business-as-usual forecast for the operated assets

-       Identify, review and prioritise potential GHG reduction options for operated assets by establishing marginal abatement cost curves

The Group has made steady progress on defining its Net Zero roadmap, which will be completed by the end of 2023.  It will disclose more details about the ongoing work in the 2022 Sustainability Report, to be published alongside the Jadestone's 2022 Annual Report in May 2023.  The Group is committed to transparency by reporting at least annually on the progress made in implementing its Net Zero roadmap.

Illustrative of its efforts to minimise Scope 1 and 2 GHG emissions from its operations, a solar photovoltaic installation was piloted at the Akatara gas field development in Indonesia in April 2022, replacing diesel generators at four well pads.  Solar power now fully meets well pad lighting and electricity needs, with potentially broader application within the Akatara development, such as the accommodation camp.  In collaboration with other operators in the area, Jadestone is also participating in the planting of over 27,000 mangrove trees to positively impact the local communities and environment.

Governance

Jadestone's sustainability framework is founded on its commitment to upholding high standards of governance and responsible, social and ethical behaviour.  Jadestone takes a strategic approach to embedding sustainability throughout its business that is overseen by the Board and supporting subcommittees.

On 7 April 2022, the Group announced the appointment of Jenifer Thien as an independent non-executive director.  She brings knowledge and experience in environmental, social and governance ("ESG") strategy and joined the Remuneration, Governance and Nomination, and Health, Safety, Environment and Climate (HSEC) committees.

On 29 April 2022, Daniel Young stepped down from his role as the Chief Financial Officer ("CFO") and Executive Director and left the Group.  Michael Horn took the role of interim CFO until 22 August 2022, when Bert-Jaap Dijkstra was appointed by the Board as CFO and Executive Director.

In 2022, the Group partnered with a specialist consultancy to update its corporate business ethics and compliance policies and further strengthen its alignment with best practice.  In addition, a Human Rights Policy, Climate Policy and External Grievance Procedure were approved by the Board and can be viewed on Jadestone's website.

Following the discovery of defects within the Montara Venture FPSO tanks which led to the field being shut in and recognising the importance of the asset, both in terms of production and its safety and integrity, Jadestone's Board established a technical committee in September 2022.  This action was taken in order to provide additional support and challenge to management during the Montara Venture FPSO hull and tank remediation work.  The technical committee received weekly progress updates and reports, and direct feedback from senior operational staff on a monthly basis.  The technical committee remains in place and will be dissolved following a satisfactory review of a third-party assessment of a 90-day period from restart in mid-March 2023.

OPERATIONAL REVIEW

Producing Assets

Australia

Montara Project

The Montara Project, in production licences AC/L7 and AC/L8, is located 254 km offshore Western Australia, in water depth of approximately 77 metres.  The Montara Project comprises three separate fields being Montara, Skua and Swift/Swallow, which are produced through an owned FPSO, the Montara Venture. 

As at 31 December 2022, the Montara assets had proven plus probable reserves of 18.5mmbbls (31 December 2021: 20.9mmbbls), 100% net to Jadestone.  

The fields produce light sweet crude (42^o API, 0.067% mass sulphur), which typically sells for average Dated Brent plus the average Tapis differential in the month of lifting.  The premium in 2022 ranged between US$3.53/bbl to US$6.19/bbl, with an average premium of US$4.70/bbl.

Since acquiring a 100% interest in the Montara Project, the Group has invested over US$250.0 million in the field, incorporating significant amounts on repair and refurbishment of the Montara Venture, including corrosion management.  However, reduced offshore manning levels and limited inter-state travel resulting from the COVID-19 pandemic slowed the pace of cargo tank inspection and repair activity onboard the Montara Venture in 2020 and 2021.

In June 2022, during routine production and crude oil cargo operations onboard the Montara Venture, approximately three to five cubic metres of oil was released to sea from a small hole in the bottom of cargo tank 2C, which while still in class, had seen a delay to its scheduled maintenance activity due to the COVID-19 impact referred to above.  A temporary repair was effected in order to remove the remaining oil from tank 2C and key stakeholders, including the Australia offshore regulator NOPSEMA, were notified. Production was safely reinstated in early July 2022, although was shut in again in August after a further defect in ballast water tank 4S, was detected.  At this point, the Group took the decision to shut-in production at Montara to prioritise tank inspection and repairs.

In September 2022, NOPSEMA issued a General Direction to the Company, which required Jadestone to engage an independent reviewer to undertake a gap recognition review, and assure the Group's remediation plans and operational readiness prior to the restart of production operations at Montara.  DNV, the world's leading maritime classification society and an independent expert in risk management and assurance, was subsequently engaged as the independent reviewer and a report submitted to NOPSEMA in January 2023.  NOPSEMA's review of the independent report was subsequently concluded and the General Direction lifted in February 2023.  The Group's policies and procedures relating to FPSO tank inspection and repair and corrosion management have been strengthened as a result of this process.

Following successful completion of tank inspection and repair activities, as well as scheduled four-yearly maintenance activities, a phased production restart campaign commenced in March 2023.  Initially, the Montara H6 well and Skua-10 and 11 wells were brought online in different configurations, with average production of 4,700 bbls/d over a 19 day period while works continued to commission the gas compression system on the FPSO, including specialist welding repairs to a reboiler. 

There was a controlled four day production shutdown of the Montara Project in April 2023 as a precautionary measure due to the impact of Cyclone Ilsa.  The facility was successfully remanned and production recommenced on 13 April from the Montara H6 well and Skua-11 well, with production since the cyclone shutdown subsequently averaging c.5,000 bbls/d, and the Skua-10 well was subsequently brought onstream.    

Oil is currently being produced into oil tank 5C, with oil tank 6C due to be returned to service shortly, with the remaining oil tanks due to come back online sequentially following planned detailed inspection and any required repairs.  To provide operational flexibility during this period, an offtake tanker has been contracted for three months and will be stationed nearby the Montara Venture until sufficient oil storage capacity is available.  This is expected to result in a one-off cost of c.US$8.0 million in 2023.

Due to the impact of the Cyclone Ilsa related shutdown, the Company now expects that the Montara Venture gas compression will be brought back onstream at the end of April 2023, which would allow further wells to become available for production.

Absent any unplanned downtime, but including eight days of scheduled downtime in October 2023 for a compressor service and assuming well and subsurface performance in line with expectations, the Company expects Montara production to average approximately 6,000 bbls/d between April and December 2023.  Montara Project oil production will become constrained by increasing gas production from Montara field reservoir until the installation of further compression on the Montara Venture, which remains in the planning phase.

Montara production averaged 4,227 bbls/d in 2022 (2021: 7,647 bbls/d), with the difference, in part, due to declines but more materially due to the production shut-in described above.  Prior to the shut-in, production during H1 2022 was 7,509 bbls/d compared to 7,269 bbls/d in H1 2021.

There were five liftings in 2022, resulting in total sales of 1.7 mmbbls of crude oil compared to 3.0 mmbbls from six liftings in 2021.

Stag oilfield

The Stag oilfield, in production licence WA-15-L, is located 60 km offshore Western Australia in a water depth of approximately 47 metres. 

As at 31 December 2022, the field contained total proved plus probable reserves of 12.1mmbbls (31 December 2021: 12.6mmbbls), 100% net to Jadestone.  

The Stag oilfield produces heavy sweet crude (18^o API, 0.14% mass sulphur), which historically sells at a premium to Dated Brent.  The premium in 2022 ranged between US$21.88/bbl to US$23.72/bbl with an average premium of US$ 22.78/bbl.  The most recent lifting in February 2023 was agreed at a premium of US$19.10/bbl.

Production was 2,176 bbls/d in 2022 compared to 2,359 bbls/d in 2021.  This decrease was predominately the result of a May 2022 shut down to perform planned pressure vessel inspections, which occur every three years.  

During H2 2022, the Stag-50H and 51H infill wells were successfully drilled, completed and brought online in November 2022, generating additional production of approximately 600 bbls/d during December 2022.

There were four liftings in 2022 for total sales of 0.8 mmbbls, compared to 1.0 mmbbls in 2021 from the same number of liftings.

North West Shelf Project

The Cossack, Wanaea, Lambert and Hermes oil fields (the "North West Shelf Project" or "CWLH Assets") are located 115km offshore Western Australia in production licences WA-3-L, WA-9-L, WA-11-L and WA-16-L situated in a water depth of approximately 80 metres.

On 28 July 2022, the Group executed a sale and purchase agreement ("SPA") with BP Developments Australia Pty Ltd to acquire BP's non-operated 16.67% working interest in the CWLH Assets for a total initial headline cash consideration of US$20.0 million, and certain subsequent contingent and decommissioning payments.  The acquisition completed on 1 November 2022, following the satisfaction of all conditions precedent.  The Group is currently applying to the National Offshore Petroleum Titles Administrator for approval of the dealing and registration on the petroleum titles relating to the acquired interest.  This is expected soon.

As at 31 December 2022, the CWLH Assets contained total proved plus probable reserves of 5.1mmbbls, net to Jadestone. 

The economic effective date of the acquisition was 1 January 2020, meaning that the Group was entitled to the net cash generated since the economic effective date to completion.  As a result, the Group obtained a net cash receipt of US$7.0 million.  Under the SPA and just prior to closing, the Group paid US$41.0 million in cash into a decommissioning trust fund held and managed by the operator.  The last two instalments of US$20.5 million each are scheduled to be paid upon OPGGS title transfer and then before 31 December 2023, respectively.

The average production since the completion date of 1 November 2022 was 2,290 bbls/d, net to Jadestone's working interest.  On an annualised basis, this was equivalent to 383 bbls/d net to Jadestone in 2022.

Jadestone lifted one cargo following completion of the acquisition, resulting in sales of 0.7 mmbbls in 2022.

Malaysia

Operated: PM 323 and PM 329 PSCs & Non-operated: PM 318 and AAKBNLP PSCs

The PenMal Assets consist of four PSCs, two of which are operated by the Group.  The two operated PSCs comprise a 70% interest in PM329, containing the East Piatu field, and a 60% interest in PM323, which contains the East Belumut, West Belumut and Chermingat fields.  Both PSCs are located approximately 230km northeast of Terengganu in shallow water.

The two non-operated (operated by others, or "OBO") PSCs consist of 50% working interests in each of PM318 PSC and the Abu, Abu Kecil, Bubu, North Lukut, and Penara oilfields (the "AAKBNLP") PSC.  The two non-operated PSCs are located in the same region as PM329 and PM323.

As at 31 December 2022, the PenMal Assets contained total proved plus probable reserves of 8.9mmboe (2022: 11.2mmboe), net to Jadestone. 

The PenMal Assets produce light sweet crude that is blended to Tapis grade (43^o API, 0.04% mass sulphur).  The premium in 2022 ranged between US$0.96/bbl to US$14.41/bbl with an average premium realised of US$6.38/bbl.  The most recent lifting in April 2023 was agreed at a premium of US$4.68/bbl.

In 2022, average production from the PenMal Assets was 3,884 bbls/d of oil and 4,908 mscf/d of gas, or 4,702 boe/d, net to Jadestone's working interest.  In 2021, the average production after taking ownership in August 2021 was 5,377 bbls/d of oil and 4,084 mscf/d of gas, or 6,057 boe/d.  The decrease of 1,355boe/d was the result of the non-operated licences PM318 and AAKBNLP being shut-in from February 2022 due to the class suspension of the FPSO which serves the non-operated PSCs.

Jadestone has assumed operatorship of the non-operated licences following the decision of the previous operator to withdraw. Jadestone believes there are significant remaining reserves on the licences and looks forward to evaluating redevelopment options for the fields.

There were 13 liftings from the PenMal Assets in 2022, resulting in total oil sales of 0.8 mmboe and total gas sales of 1.8 mmscf, compared to total oil sales of 0.6 mmboe and total gas sales of 0.6 mmscf in 2021 achieved between the date of acquisition up to 2021 year-end.

Pre-production Assets

Indonesia

Lemang PSC

The Lemang PSC is located onshore Sumatra, Indonesia.  The PSC contains the Akatara field, which has been substantially de-risked with 11 wells drilled into the structure, plus three years of oil production history, up until the field ceased oil production in December 2019.  Jadestone is redeveloping Akatara to supply gas, condensate and LPGs for local and regional use.

The Akatara gas field has been independently estimated to contain 2P gross reserves (pre local government back-in rights) of 71.1 bcf of sales gas, 2.2 mmbbls of condensate and 8.4 mmboe of LPG, equating to a combined 22.5 mmboe of resource.  Following completion of the Hexindo acquisition (see below) Jadestone currently has a 100% interest in the Lemang PSC, with the local government retaining a 10% back-in right, which is expected to be exercised prior to first gas.

On 1 December 2021, a gas sales agreement was signed between Jadestone and PT Pelayanan Listrik Nasional Batam, as buyer. 

On 6 June 2022, the Group announced that a final investment decision had been taken on the Akatara field development following the necessary approvals by the Indonesian upstream regulator.  The Group awarded the engineering, procurement, construction and installation contract on 3 June 2022 and development activities commenced.  As at 7 April 2023, the Akatara development project is approximately 28.3% completed and first gas remains on schedule for the first half of 2024.

On 23 November 2022, the Group completed the acquisition of the remaining 10% interest in the Lemang PSC.  The 10% interest was acquired through the execution of a Settlement and Transfer Agreement between the Group and PT Hexindo Gemilang Jaya ("Hexindo").  In return for the transfer of Hexindo's 10% stake, the Group paid a cash consideration of US$0.5 million and released Hexindo from previously unpaid amounts relating to Hexindo's interest in the Lemang PSC.

Vietnam

Block 51 and Block 46/07 PSCs

Jadestone holds a 100% operated working interest in the Block 46/07 and Block 51 PSCs, both in shallow water in the Malay Basin, offshore southwest Vietnam. 

The two contiguous blocks hold three discoveries: the Nam Du gas field in Block 46/07 and the U Minh and Tho Chu gas/condensate fields in Block 51, with aggregate 2C contingent resources of 93.9 mmboe.

The Tho Chu discovery in Block 51 is currently under a suspended development area status.  A request for an extension to the Tho Chu suspended development area status has been submitted to the industry regulator and is expected to be granted in due course.

Jadestone continues to negotiate with the proposed buyer of gas from its offshore discoveries, aiming to sign a Heads of Agreement in the near-term for gas sales from the Nam Du/U Minh development.  Following a gas sales agreement, the Group would work to finalise the field development plan and submit this for approval, a key step towards commercialising this significant and strategic resource in Jadestone's licences.  Development of this resource would lessen Vietnam's future dependence on expensive LNG imports and would contribute towards the country's energy transition and stated goal of Net Zero greenhouse gas emissions by 2050.

Reserves and resources

As at 31 December 2022, the Group had proved plus probable oil reserves ("2P Reserves") of 64.8 mmboe, a 45% increase compared with year-end-2021 and a near six-fold replacement of production in the year.  The primary drivers of the significant increase in reserves were the reclassification of 2C Contingent Resources from the Akatara gas field development in Indonesia to 2P Reserves following a final investment decision in June 2022, as well as the acquisition of the 16.67% interest in the producing CWLH fields offshore Australia, which completed in November 2022.  Jadestone completed the acquisition of an interest in the Sinphuhorm gas field onshore Thailand, adding a further 4.1 mmboe of 2P Reserves, after the period end and therefore not included in 2022.

The Group's best case contingent resources ("2C resources") decreased slightly from 110.7 mmboe in 2021 to 104.3 mmboe in 2022.  The reclassification of the Akatara gas development contingent resources to 2P reserves was partially offset by the inclusion of the Group's share of contingent resources associated with the potential life extension of, and infill drilling on, the CWLH Assets, as well as additional Akatara upside potential identified in excess of the volumes covered under the gas sales agreement.

¹ Proven and Probable Reserves for Jadestone's assets have been prepared in accordance with the June 2018 SPE/WPC/AAPG/ SPEE/SEG/SPWLA/EAGE Petroleum Resources Management System ("PRMS") as the standard for classification and reporting.

² Assumes oil equivalent conversion factor of 6,000 scf/boe.

³ Contingent Resources based on ERCE estimates as at 31 December 2022, except for Vietnam 2C resources which are based on ERCE Competent Person's Report effective 31 December 2017.

FINANCIAL REVIEW

The following table provides select financial information of the Group, which was derived from, and should be read in conjunction with, the preliminary unaudited consolidated financial statements for the year ended 31 December 2022.

Benchmark commodity price and realised price

The average Brent price incorporated into the Group's liftings was US$101.32/bbl in 2022, an increase of 43% compared to the US$70.91/bbl achieved in 2021

The actual average realised price in 2022 increased in line with the benchmark price, by 40% to US$103.85/bbl, compared to US$74.34/bbl in 2021.  The average realised premium for the year was US$7.81/bbl, compared to US$3.39/bbl in 2021.  All producing assets saw an increase in premium, with Stag averaging US$22.78/bbl (2021:11.20/bbl), Montara US$4.70/bbl (2021: US$1.14/bbl) and PenMal operated assets US$6.67/boe (2021: US$1.62/boe).

The premiums have subsequently reduced from their peak in Q3 2022 with the most recent liftings in 2023 achieving a premium of US$19.10/bbl at Stag and US$4.68/bbl at the PenMal Assets. 

Production and liftings

The Group produced an average of 11,487 boe/d in 2022, compared to 12,545 boe/d in 2021.  Production decreased predominately due to the shut-in of Montara from mid-August 2022 to mid-March 2023.

Montara production declined 45% to 4,227 bbl/d in 2022 from 7,647 bbl/d in 2021 due to the shut-in of production from mid-August 2022 to mid-March 2023 following a management decision to suspend operations to focus on FPSO hull and tank repairs.  Stag production in 2022 was 2,176 bbl/d, a decrease from 2021 of 2,359 bbls/d predominately due to a once-in-every-three-year routine shutdown.  Lower production at Stag and Montara was partly offset by a full year of production from the PenMal Assets of 4,702 boe/d in 2022 compared to 2,539 boe/d in 2021, and the acquisition of the CWLH Assets contributing an annualised production of 383 bbls/d.  The production rate from the CWLH Assets since acquisition on 1 November 2022 was 2,290 bbl/d.

¹ Realised oil price represents the actual selling price inclusive of premiums.

² Operating cost per boe, adjusted EBITDAX and net cash are non-IFRS measures and are explained in further detail on the Non-IFRS Measures section in this document.

The Group had 22 liftings during the year (2021: 17), mainly due to a full year of production and liftings from the PenMal Assets in 2022 compared to 2021 when the assets were owned for part of the year.  Total Group's sales of 4.3 mmboe in 2022 included lifted volumes of 0.7 mmbbls from the CWLH Assets, a decrease compared to 4.7 mmboe in 2021 due to the lower production at Montara and the non-operated PenMal Assets.

Revenue

The Group generated revenue of US$421.6 million in 2022, an increase of 24% compared to 2021 of US$340.2 million.  This represents the highest revenue ever recorded by the Group.  The increase of US$81.4 million was predominately due to:

·      Higher average realised prices in 2022, compared to 2021, contributing an additional US$150.8 million;

·      A reduction in lifted volumes year-on-year resulting in decreased revenue of US$128.2 million (excluding price effects);

·      The acquisition of the CWLH Assets in November 2022, which contributed US$56.6 million; and

·      PenMal Assets generating higher gas revenue of US$2.1 million compared to US$1.0 million in 2021.

Production costs

Production costs increased by 30% in 2022 to US$250.7 million, from US$211.9 million in 2021, predominately due to:

·      The acquisition of the CWLH Assets in November 2022 incurred production costs of US$37.7 million.  This production cost is impacted by the accounting treatment of underlift at acquisition.  This underlift of 315kbbls was recorded at fair value of US$27.3 million based on the market oil price of US$86.68/bbl.  Please refer to Note 5 of the Group's consolidated financial statements for further details.  The actual production cost per barrel was US$20.58/bbl, being the actual cash cost since the acquisition on 1 November 2022;

·      Full year operations at the PenMal Assets, compared to five months in 2021, caused an increase in production costs by US$31.8 million which included a full year of supplementary payments with an increase of US$16.3 million, as a result of realised prices exceeded the PSC escalated base price;

·      Production costs of Montara decreased by US$18.9 million reflecting the higher-than-normal workover costs at Skua 10/11 in 2021, partly offset by higher repairs & maintenance and logistics costs in 2022.  The total repairs & maintenance costs directly associated with the FPSO hull and tank repairs was US$3.8 million; and

·      Stag production costs decreased by US$11.8 million year-on-year predominately due to a decrease in workover activities in 2022.

Unit operating costs per barrel of oil equivalent were US$37.49/boe (2021: US$26.22/boe), before workovers and movement in inventories, but including net lease payments and certain other adjustments (see Non-IFRS measures section below in this document).  The increase in unit costs reflects the reduction in production at Montara and non-operated PenMal Assets.

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

DD&A charges were US$61.8 million during the year, compared to US$80.2 million in 2021, predominately due to the lower production at Montara, resulting in a decrease of US$20.2 million.  The reduction was partly offset by additional depletion charges at the CWLH Assets of US$1.7 million, since the date of acquisition of 1 November 2022.

Depreciation of the Group's right-of-use assets increased to US$13.0 million in 2022 from US$11.2 million in 2021, primarily due to the extension of a two-year lease for airport services to replace an expired lease.

The depletion cost on a unit basis was US$10.80/boe in 2022 (2021: US$13.67/boe), due to the lower depletion per unit of production at the PenMal Assets.  The unit depletion cost in 2022 for the PenMal Assets was US$1.76/boe compared to US$3.87/boe in 2021.  This was due to the absence of production from the non-operated PSCs which incurs a higher unit depletion rate. 

The combined depletion cost per unit at both Stag and Montara increased to US$17.35/bbl from US$16.16/bbl in 2021 for the capital expenditures spent in 2021.  The CWLH Assets recorded a unit depletion cost of US$12.36/bbl.

Staff costs

Total staff costs in 2022 were US$55.3 million, comprising US$26.1 million (2021: US$26.8 million) in relation to offshore employees, recorded under production costs, and US$29.2 million (2021: US$25.1 million) for office-based employees.  The average number of employees during the year was 369 (2021: 278), with the additional staff costs and headcount year-on-year predominately associated with the PenMal Assets following completion of the acquisition in August 2021.

Other expenses

Other expenses decreased in 2022 to US$22.3 million (2021: US$26.2 million).  The variance of US$3.9 million was predominately due to:

·      Reduction of non-recurring costs by US$3.6 million compared to 2021.  In 2022, the Group incurred non-recurring costs of US$1.6 million, relating to the acquisition of CWLH Assets, business development and various other one-off projects.  In comparison, the Group incurred total non-recurring costs of US$5.2 million in 2021, which included internal reorganisation costs of US$1.1 million, acquisition costs of US$0.8 million associated with the PenMal Assets, and several other business development related expenses of US$3.3 million;

·      The 2021 costs included a fair value loss on commodity swaps of US$4.6 million related to hedge contracts.  The Group had no hedging in 2022;

·      Assets written off reduced US$4.9 million to US$0.2 million in 2022 due to the prior year impairment of exploration assets.

·      Net foreign exchange loss of US$0.4 million in 2022 (2021: US$1.0 million);

·      Additional contingent payments related to the future Dated Brent prices and Saudi CP prices associated with the Lemang PSC of US$7.3 million were recognised in 2022; and

·      Higher provisions for slow-moving materials and spares on hand in 2022 of US$3.8 million (2021: US$2.6 million).
 

Other income

Other income of US$28.0 million was generated during 2022 compared to US$7.7 million in 2021, due to:

·      Insurance claim receipts of US$18.0 million compensating for loss of production at Montara related to drilling activities at Skua 10/11 in 2021;

·      Rebate income of US$5.0 million (2021: US$4.5 million) arose from the sublease of right-of-use assets under the Group's helicopter lease contract; and

·      Net foreign exchange gains of US$0.5 million (2021: US$2.5 million).

Impairment

In 2021, the Group recorded an impairment of US$13.5 million associated with the oil and gas properties of the non-operated PenMal Assets, following the decision by the operator to shut-in production after the FPSO class suspension in February 2022.  The impairment of US$13.5 million comprised US$6.9 million of oil and gas properties written off and US$6.6 million associated with the 2022 year end revaluation of decommissioning estimates embedded in the ARO provision.

As at 31 December 2022, the fields were shut-in and management does not expect to restart production in 2023 while the Group is exploring strategic alternatives, including a potential redevelopment of the non-operated PenMal Assets.                                                   

Taxation

The tax charge of US$54.0 million in 2022 (2021: US$12.8 million) which includes a current tax charge of US$27.1 million (2021: US$7.3 million) and a deferred tax charge of US$26.9 million (2021: US$5.4 million). 

The tax paid during the year included US$18.5 million of corporate tax payments and Australian petroleum resource rent tax ("PRRT") tax refund of US$1.1 million in Australia, plus US$15.7 million of PITA tax in Malaysia.

The weighted average effective tax rate based on profit jurisdictions was 56% (2021: 49%).  The consolidated group effective tax rate is 86% (2021: -198%) as loss making jurisdictions negatively impact profit before tax.  The profit before tax from Australia and Malaysia was US$87.6 million (2021: US$15.3 million), which was impacted by corporate, development and exploration losses of US$25.0 million (2021; US$19.6 million).  The corporate tax losses are not recognised as deferred tax as there is not sufficient certainty that taxable income will be realised in the future.

Australia Taxes

The Australian corporate income tax rate is 30% and PRRT is 40% which is cash based and income tax deductible.  The combined standard effective tax rate is 58%, the actual effective tax rate of 46% is lower predominately due to the utilisation of PRRT credits brought forward at Montara.  Montara has approximately US$3.5 billion of unutilised PRRT credits and is not expected to incur any PRRT expense over the economic life of the asset.

Malaysia Taxes

Malaysian petroleum income tax ("PITA") is a PSC based tax on petroleum operations at the rate of 38%.  There are no other material taxes in Malaysia.  The Group incurred losses from the non-operated PSCs (PM318 / AAKBNLP) as a result of ceasing production in February 2022, which resulted a tax non-deductible impairment of $13.5 million.  There has been a significant increase in deferred tax permanent taxable difference which predominately relate to changes in the ARO estimates at year end which won't be tax deductible at the end of the field life when the Group commences decommissioning activities due to insufficient estimated taxable income.

2022 RECONCILIATION OF NET CASH

The movement in working capital and the placement of decommissioning trust fund for CWLH Assets are combined in the consolidated statement of cash flows for the year ended 31 December 2022 under the movements in working capital.

NON-IFRS MEASURES

The Group uses certain performance measures that are not specifically defined under IFRS, or other generally accepted accounting principles.  These non-IFRS measures comprise operating cost per barrel of oil equivalent (opex/boe), adjusted EBITDAX, outstanding debt, and net cash.

The following notes describe why the Group has selected these non-IFRS measures.

¹ Total capital expenditure was US$82.9 million (2021: US$56.0 million), comprising total capital expenditure paid of US$82.6 million (2021: US$55.9 million), plus accrued capital expenditure of US$0.3 million (2021: US$0.1 million).

Operating costs per barrel of oil equivalent (Opex/boe)

Opex/boe is a non-IFRS measure used to monitor the Group's operating cost efficiency, as it measures operating costs to extract hydrocarbons from the Group's producing reservoirs on a unit basis. 

Opex/boe is defined as total production costs excluding oil inventories movement and underlift/overlift, write down of inventories, workovers (to facilitate better comparability period to period) and non-recurring repair and maintenance.  It includes lease payments related to operational activities, net of any income earned from right-of-use assets involved in production, and excludes transportation costs, PenMal Asset supplementary payments, DD&A and short-term COVID-19 subsidies. 

The adjusted production cost is then divided by total produced barrels of oil equivalent for the prevailing period to determine the unit operating cost per barrel of oil equivalent.

¹ Lease payments related to operating activities are lease payments considered to be operating costs in nature, including leased helicopters for transporting offshore crews.  These lease payments are added back to reflect the true cost of production.

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

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

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

⁵ Non-recurring repair and maintenance costs in 2022 predominately related to Montara Skua-11 repair works, gas compressor solar engine change out and tank repairs following the shut-in of Montara in August 2022.

⁶ The supplementary payments are required under the terms of PSCs based on Jadestone's profit oil after entitlements between the government and joint venture partners.   The Australian royalties were related to local decommissioning cost recovery levy plus royalties payable to the local state government arose from the acquisition of the CWLH Assets.

⁷ PenMal non-operated assets FPSO rectification costs refer to the costs incurred to repair the FPSO BUK CLASS at PM318 and AAKBNLP PSCs following its suspension in February 2022.

Adjusted EBITDAX

Adjusted EBITDAX is a non-IFRS measure which does not have a standardised meaning prescribed by IFRS.  This non-IFRS measure is included because management uses the information to analyse cash generation and financial performance of the Group.

Adjusted EBITDAX is defined as profit from continuing activities before income tax, finance costs, interest income, DD&A, other financial gains, non-recurring expenses and exploration assets write-offs.

The calculation of adjusted EBITDAX is as follow:

¹ Includes one-off major maintenance/well intervention activities, in particular the Montara Skua-11 repair works, gas compressor solar engine change out and storage tank repairs after the Montara production shut-in since mid-August 2022.  

² Represents insurance claim received at Montara for the compensation for the loss of production relating to drilling activities at the two Skua field wells in 2020.  The 2021 insurance claim receipt was received at Montara and related to the well control claim for the Skua 11 well workovers.

³ Includes business development costs, external funding sourcing costs, Maari transition team costs and internal reorganisation costs.

Debt

As at 31 December 2022, the Group had no outstanding borrowings.

As part of its previously announced plan to arrange a RBL, on 17 February 2023, the Group entered into a US$50.0 million Interim Facility with two international banks.  The Interim Facility has a term of nine months and carries an initial margin of 450 basis points over SOFR, which steps up in the event repayment occurs more than three months after closing.  Subsequently, US$28.5 million of the Interim Facility was drawn principally to fund the acquisition of a 9.52% interest in the Sinphuhorm gas field in February 2023, with the remaining US$21.5 million solely being available to fund the next US$20.5 million instalment of the CWLH abandonment trust funding and related Interim Facility expenses.

The Group continues to make good progress on the RBL workstreams, with one international bank credit approved and three others in the credit approval process, with signing of the RBL facility agreement targeted for May 2023.  Once signed, the RBL is expected to close shortly thereafter once all customary conditions precedent are satisfied.  It is expected that approval from NOPTA of the transfer of titles relating to the acquisition for the CWLH fields interest will be required prior to drawing down the RBL.

The Group is finalising the final phase of its corporate restructuring which commenced with the previously announced internal reorganisation in 2021.  Creating a subsidiary holding the Group's producing assets to facilitate the RBL is an element of this. Currently, the final entity transfers are pending regulatory approval by NOPTA for transfer of the Australian entities, and whilst the transfer of the Malaysian operations has been approved by PETRONAS (the Malaysian regulator) effective 1 April 2023, the parties are finalising related contract novations to reflect PETRONAS' given approval.  The NOPTA approval for the transfer of the Australian entities and the relevant contract novations in respect of transfer of the Malaysian operations are expected in May 2023.  The finalisation of the internal restructuring is not expected to hold up the closing of the RBL.

Once closed and the conditions precedent satisfied, the Group intends to draw down the RBL to fund planned 2023 activity, particularly at the Akatara gas development as well as enabling further acquisitions.

The Directors have a high degree of confidence that the RBL facility agreement will be entered into by late May 2023. In the event that it is not, a third-party non-dilutive offer of funding has been received, which in combination with the Interim Facility, would provide sufficient liquidity to protect key capital and operating expenditures.

As is normal, the Group expects to hedge a proportion of its future production as part of its commitments under the RBL.  This is currently expected to take the form of a rolling hedge programme, commencing with an initial hedge for 40% of lifted oil volumes between Q4 2023 and Q3 2024 (inclusive).  Additional hedges on a forward rolling basis will be based on management's outlook, with a minimum of 20% of oil volumes to meet commitments under the RBL.

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.  This measure is used to ensure capital is managed effectively in order to support ongoing operations, and to raise additional funds, if required.

Net cash is defined as the sum of cash and cash equivalents and restricted cash, less outstanding borrowings, of which there were none at 31 December 2022.

Consolidated Statement of Profit or Loss and Other Comprehensive Income

for the year ended 31 December 2022

*Certain 2021 comparative information has been restated. Please refer to Note 45. 

All comprehensive income is attributable to the equity holders of the parent.

Consolidated Statement of Financial Position as at 31 December 2022

*Certain 2021 comparative information has been restated and reclassified between line items. Please refer to Note 45.