Interim results

Kistos Holdings PLC

25 September 2024

Kistos Holdings plc

("Kistos", the "Company", or the "Group")

Interim results for the six months to 30 June 2024

Kistos (LSE: KIST), the gas and oil producer pursuing opportunities across the energy value chain, is pleased to provide its interim results for the period to 30 June 2024.

Financial

· Net daily production averaged 8,400 boepd across Norway, Netherlands, and the UK (H1 2023 pro-forma: 9,200 boepd)

o Stronger than expected production from the Greater Laggan Area and expansion of the Ringhorne platform more than offset a short unplanned shutdown of the P15 processing platform in the Netherlands

· Revenues and Adjusted EBITDA decreased compared with H1 2023, reflecting lower commodity prices

· Cash at the end of the period of $72 million, reflecting investment in the acquisition of EDF's gas storage assets, the settling of UK tax liabilities, and capital expenditure in Norway's Balder Future project

· Net debt at the end of the period stood at $175 million

6 months ended 30 June 2024

		H1 2024	H1 2023 (pro forma, restated)²	Change %
Total production rate¹	boepd	8,400	9,200	-9%
Revenue	$'000	113,328	129,722	-13%
Average realised oil price	$/bbl	82l	76l	+8%
Average realised gas price	$/boe	54	80	-33%
Adjusted EBITDA²	$'000	48,585	73,886	-34%

1. Total production rate includes gas, oil and natural gas liquids and is rounded to the nearest 100 barrels of oil equivalent per day. Sales and production volumes are converted to estimated barrels of oil equivalent (boe) using the conversion factors in the Appendix to the Interim Financial Statements.

2. Non-IFRS measure. See note 2.2.1 to the Interim Financial Statements for definition and reconciliation to the nearest equivalent IFRS measure.

3. Pro forma H1 2023 figures include the results from Kistos Norway as if it had been acquired on 1 January 2023. The acquisition completed on 23 May 2023.

Comparative financial figures have been restated due to a change in presentational currency from EUR to USD (see note 1.4 to the interim financial statements).

Operational

· Production totalled 1.5 mmboe, with daily production averaging 8,400 boepd (H1 2023: 9,200 boepd)

· Net production from the Balder, Ringhorne and Ringhorne Øst fields averaged 2,800 boepd (H1 2023: 2,200 boepd), reflecting both the two new wells drilled from the Ringhorne platform, and an overall production efficiency of 93% in H1 2024 (versus 82% in H1 2023)

· Net Q10-A (Kistos 60% and operator) production averaged 2,200 boepd (H1 2023: 3,100 boepd) due to an unplanned shutdown and planned maintenance on the TAQA-operated P15-D platform

· Net production from Kistos' interest in the Greater Laggan Area was above expectations at an average rate of 3,400 boepd (H1 2023: 4,300 boepd)

· Completed the acquisition of EDF's Hill Top Farm and Hole House onshore gas storage assets in Cheshire, UK, for £25 million

o During May and June, Kistos successfully undertook the fifth and final phase of a 'soft cycling' trial, resulting in a 24% uplift of working gas capacity

· Full-year production guidance for 2024 is 7,500 - 8,500 boepd

Outlook

· In Norway, the Balder Future project progressed with the West Phoenix rig completing the drilling of 14 production wells and commenced operations on the water injection well, which was completed post-period

· First oil from the Balder Future project is now anticipated by the end of Q2 2025, with Kistos protected from the associated cost increase by the $45 million Hybrid Bond. This is only payable if 500,000 gross is lifted from the Jotun FPSO before 31 May 2025

· The GLA joint venture partners are prioritising the Glendronach development, and Kistos anticipates that a new operator of the GLA will add additional momentum for sanctioning development projects to extract near-term value

· During the period, the Victory field (Shell 100%) achieved regulatory approval. This is due to come onstream via the Shetland Gas Plant facilities in Q4 2025, extending the GLA's life and substantially reducing its Unit operating costs of the GLA fields

· In the Netherlands, the second phase of Concept Select for the Orion oil development was concluded successfully, and FID is awaiting clarity on the status of projects to extend the life of existing third-party infrastructure

· Undertaking the front-end engineering and design work to evaluate the possibility of recommissioning the Hole House facility, which has the potential to increase the working capacity of the onshore UK gas storage site by over 60%

Andrew Austin, Executive Chairman of Kistos, commented:

"Maintaining high operational standards and continuing to convert the organic opportunities within our portfolio is central to realising value for shareholders. We have managed a season of planned and unplanned maintenance, keeping production downtime to a minimum, and remain on track to meet our full-year production guidance of between 7,500 - 8,500 boepd.

Alongside our partners in the GLA joint venture, we have prioritised the Glendronach development, which will provide both production upside and further extend the life of the Shetland Gas Plant alongside expected new third-party throughput. Despite the delay to first production at the Balder Future project to Q2 2025, which will have no adverse economic impact for Kistos, operational progress has continued with the completion of production drilling activity.

We continue to pursue a pro-active M&A strategy, constantly assessing opportunities across the value chain. In April, we completed the acquisition of EDF's gas storage facilities in Cheshire, marking an expansion of Kistos' midstream footprint. We have moved quickly to maximise the economic return of the site, completing a soft cycling relaxation trial at Hill Top Farm which confirmed the ability to increase working gas capacity by 24% from 17.8 million to 22 million therms. Importantly, this acquisition sits outside of the upstream oil and gas tax regime, offering us greater exposure to normalised levels of taxation on our profits.

Looking ahead, the priority remains both operational delivery and continuing to seek out inorganic growth opportunities. We are committed to ensuring that any transaction offers meaningful near-term value creation for shareholders, on an acceptable risk profile. This strategy of pursuing deals not just at the right price but on the right terms, has been validated by the mitigations put in place around the timing of the Balder Future project, where we've protected shareholders from additional cost whilst maintaining exposure to significant upside potential."

Enquiries

Kistos Holdings plc Andrew Austin, Executive Chairman	via Hawthorn Advisors
Panmure Liberum (NOMAD, Joint Broker) James Sinclair-Ford / Dougie McLeod / Mark Murphy	Tel: 0207 886 2500
Berenberg (Joint Broker) Matthew Armitt / Ciaran Walsh	Tel: 0203 207 7800
Hawthorn Advisors (Public Relations Advisor) Henry Lerwill / Simon Woods	Tel: 0203 745 4960
Camarco (Public Relations Advisor) Billy Clegg	Tel: 0203 757 4983

Notes to editors

Kistos was established to acquire and manage companies in the energy sector engaging in the energy transition trend. The Company has undertaken a series of transactions including the acquisition of a portfolio of natural gas production assets in the Netherlands from Tulip Oil Netherlands B.V. in 2021. This was followed in July 2022, with the acquisition of a 20% interest in the Greater Laggan Area (GLA) from TotalEnergies, which includes four producing gas fields. In May 2023, Kistos completed its third acquisition, acquiring the total share capital of Mime Petroleum and its Norwegian Continental Shelf Assets. These comprise a 10% stake in the Balder joint venture which spans the Balder and Ringhorne oil fields, alongside a 7.4% stake in the Ringhorne East field. In April 2024 Kistos completed its fourth acquisition, purchasing a gas storage business from EDF Energy Storage which due to the fast cycle nature of the facility, can deliver up to 11% of the UK's flexible daily gas capacity if called upon.

Kistos' operated gas production activities offshore of the Netherlands continue to produce with a very low carbon intensity, with estimated Scope 1 CO₂e emissions of less than 0.01 kg/boe in H1 2024.

https://www.kistosplc.com

Kistos Holdings plc - 2024 Interim Report

Highlights

In the Netherlands, net production from the Kistos-operated Q10-A field was 2,200 barrels of oil equivalent per day (boepd) in the first half of 2024 (H1 2023: 3,100 boepd). Production was impacted by an unplanned shutdown of the P15-D processing platform during February and the commencement of the planned maintenance window from the 22^nd June.

In Norway, net production in the six months to 30 June 2024 was 2,800 boepd (H1 2023: 1,700 boepd pro forma). During the period, 2 wells were drilled from the Ringhorne platform, which aided production rates. The West Phoenix semi-submersible rig continued its programme to drill and complete 15 wells relating to the Balder Future project. By the end of June, all 14 production wells had been finished and the rig had commenced operations on the sole water injection well, which was subsequently finished in late July.

In the UK, net production of 3,400 boepd (H1 2023: 4,300 boepd) from the Greater Laggan Area ("GLA") fields was higher than planned due to strong output following the unplanned shutdown during December 2023. Operations were impacted in May by a planned 21-day turnaround at the Shetland Gas Plant ('SGP'), which was completed on schedule. Shell's Victory field development, which received regulatory approval in January, will utilise the SGP and other GLA infrastructure and remains on schedule for first gas by the end of 2025. Within the GLA itself and after a further review of the relative merits of the two near-term opportunities, the JV partners have decided to focus on the Glendronach project rather than Edradour West. The JV also continues to analyse the 4D seismic shot in 2023 for further infills targets in Laggan, Tormore and Glenlivet.

In June, TotalEnergies announced the sale of its remaining 40% operated stake in the west of Shetlands assets to Prax Upstream Limited (formerly Hurricane Energy Plc). We are supportive of the change of operator and anticipate that the JV will continue to work up development opportunities that have been identified following the successful 2023 seismic acquisition campaign.

In April 2024, we completed the acquisition of EDF's UK gas storage business which was renamed Kistos Energy Storage Limited, and comprises two facilities - Hill Top Farm and Hole House - on a single site at Warmingham in Cheshire. Since then, we have commenced a partnership with a third-party to trade the available working gas on our behalf. Following the successful final phase of a "soft cycling" trial in May, we have increased the working gas capacity of the operational Hill Top Farm facility by c.24%. We have also now commenced a FEED (Front-End Engineering and Design) study to investigate the potential to re-instate the currently non-operational Hole House facility and expect to make a Final Investment Decision in late-2024 or early-2025.

Unrestricted cash at the end of the period was $70 million (31 December 2023: $215 million), The decrease was due to ongoing capital expenditure requirement in Norway, the settlement of UK tax liabilities, and cash consideration paid for the acquisition of EDF's gas storage assets. Net debt at the end of the period was $175 million (31 December 2023: $27 million). Net debt excludes the face value of Hybrid Bonds ($45 million), which only become payable in full or in part if the Jotun floating production storage and offloading vessel (FPSO) has offloaded its first cargo by 31 May 2025.

		H1 2024	H1 2023¹	Change %
Average production rate^2,3	boepd	8,400	9,200	-9%
Revenue	$'000	113,328	129,722	-13%
Average realised oil price	$/bbl	82	76	+8%
Average realised gas price	$/boe	54e	80e	-33%
Adjusted EBITDA⁴	$'000	48,585	73,886	-34%

1. Comparative figures are pro forma and include the results from Kistos Energy Norway as if it had been acquired on 1 January 2023. Financial comparatives have been restated due to a change in the Group's presentational currency - see note 1.4 to the Interim Financial Statements.

2. Total production rate includes gas, oil and natural gas liquids and is rounded to the nearest 100 barrels of oil equivalent (boe) per day. Average production rates include the impact from acquired businesses only from the date of acquisition completion.

3. Sales and production volumes are converted to estimated boe using the conversion factors in Appendix C to the Interim Financial Statements. Average realised price is a non-IFRS measure. Refer to the definition within the glossary.

4. Non-IFRS measures. See note 2.2.1 to the Interim Financial Statements for definition and reconciliation to the nearest equivalent IFRS measure.

Outlook

In Norway, production at the Balder FPU is expected to remain steady, with the addition of one new well from the Ringhorne platform anticipated to start production before the end of the year. In August the operator of the Balder Area, Vår Energi, announced that first oil from the Balder Future project is now anticipated before the end of Q2 2025 rather than previous guidance of start-up during Q4 2024. Vår also reported that capital expenditure on Balder Future is forecast to increase by c.$400 million gross ($40 million net to Kistos, of which $8.8 million is the approximate post-tax impact). Approximately 75% of the additional capital expenditure is expected to be incurred in 2025 and, in the meantime, the tax rebate in respect of 2023, to be repaid to Kistos in December 2024, is expected to be approximately $84 million.

When Kistos acquired Mime Petroleum in May 2023 such a scenario was envisaged. In the deal structuring with the bondholders (who effectively controlled the company at the time) we protected Kistos from such a delay and cost increase by modifying the terms of the $45 million Hybrid Bond. The Hybrid Bond was restructured such that if 500,000 bbls (gross) was not lifted from the Jotun FPSO before 31 May 2025 then the full $45 million is not payable and the Hybrid Bond would be cancelled. Therefore, the Board of Kistos is confident that there will be no adverse impact from the delay. Indeed, it is likely that the negative effect of the delay and the increase in capital expenditure will be significantly less than the positive effect of the Hybrid Bond not being paid in full.

In reaching the decision to delay Balder Future, a key consideration was to limit as much as possible the carryover of work on the Jotun FPSO into the offshore installation and start-up phase. With all development wells completed and all subsea production systems installed, the plan now is to complete the FPSO fully onshore. Importantly, once it is on station, the Jotun FPSO will enable future growth opportunities. Balder Phase V is being progressed, including the drilling of six production wells to utilise the remaining subsea template well slots to capture gross 2P reserves in excess of 30 mmboe. Drilling of these wells will commence in the first half of 2025 and be completed in 2026.

In the UK, the GLA joint venture partners continue to focus on progressing the Glendronach development after agreeing that it represents a more attractive opportunity than Edradour West at this time. In conjunction with expected new third-party throughput across the Shetland Gas Plant (SGP), Glendronach would extend the life of the existing facilities and give more certainty to potential future developments, such as additional infill wells, and to other third parties that are evaluating potential development projects in the area. Kistos also expects that the announced change in operator of the GLA joint venture (expected to complete in 2025, subject to regulatory approval) will provide additional momentum in sanctioning development projects to extract near-term value from the fields. On 21 August 2024 we announced that the NSTA had awarded a 33^rd round licence to a joint venture in which Kistos (33.3%) is partnered with TotalEnergies (66.7%, operator). The seven full or part blocks that have been offered reflect the full acreage that the partnership applied for in January 2023 and are all within the vicinity of the existing GLA footprint. The committed work programme is focussed on subsurface evaluation techniques which should improve our estimation of the potential prospectivity in the area before any decisions will be taken on whether to progress with further work or not.

In the Netherlands, the second phase of Concept Select for the Orion oil development was concluded successfully, and further progress is awaiting clarity on the status of projects to extend the life of existing third-party infrastructure. In the meantime, our team in the Netherlands continues to evaluate opportunities to enhance production from existing wells at Q10-A and to lower costs by working collaboratively with other users of the P15-D platform. Kistos is also awaiting the outcome of the application to extend the deadline to drill an appraisal well on the M10a and M11 licences, prior to commencing any assessment phase planning work.

Kistos exited 2023 with 2P reserves of 27.9 mmboe. Production in H1 2024 was 1.5 mmboe, giving 2P reserves at 30 June of 26.4 mmboe. 2C contingent resources were estimated to be 67.5 mmboe at the end of 2023. Production guidance for full year 2024 is maintained in the 7,500-8,500 boepd range.

On the newly acquired gas storage assets in the UK, Kistos has already successfully increased the working gas capacity of the Hill Top caverns by 24% and our trading partner has traded the working gas capacity significantly more actively than the previous owner. Kistos is now evaluating the economics of recommissioning the Hole House facility, which has the potential to increase the working capacity of the site by over 60%. This study is due to complete during H2 2024.

The Group continues to evaluate several value-accretive business development opportunities in the traditional energy sector, despite challenging fiscal environments, and also in the energy transition space.

Chairman's Statement

I am delighted to be able to report Kistos' interim results covering the six months to 30^th June 2024. Adjusted EBITDA for the period was $49 million and cash balances at the end of the period were $72 million. This was after acquiring EDF's onshore gas storage business in the UK for £25 million and $83 million of capital expenditure, mainly on the Balder Future project in Norway.

Our balance sheet strength means we remain well placed to grow the business, and after completing four acquisitions in four years from a standing start, we continue to evaluate a pipeline of business development opportunities. While we assess other potential acquisitions, we are also pursuing the organic growth opportunities within our existing portfolio.

In Norway, Balder Phase V is progressing and entails the drilling of six new production wells. These will utilise the remaining subsea template well slots and capture gross 2P reserves of over 30 mmboe. Drilling of these wells will commence in the first half of 2025 and be completed in 2026. In addition, the Balder Phase VI project is being matured, with the aim of adding new subsea facilities and wells, and an investment decision expected in the first half of 2025.

In conjunction with our JV partners, we continue to review the offshore UK development plan for Glendronach, which previously passed all technical stage gates with the operator and partners. This project, coupled with potential infill drilling elsewhere in the GLA plus third-party opportunities, could contribute substantially to the overall life extension of the area.

Finally, we have already increased the working gas capacity of the Hill Top gas storage facility by 24%, despite only acquiring it towards the end of April. We are now evaluating the economics of recommissioning the Hole House facility, potentially increasing our exposure to the growing role that fast cycle gas storage facilities will play in the energy transition.

On behalf of our shareholders, we remain intent on building a first-class energy business that secures supplies to ease the energy crisis and drive transition. We have taken great strides in a short period of time, and we will continue to pursue rapid, disciplined growth both organically and through acquisitions.

Andrew Austin

25 September 2024

Review of Operations

Norway production

Production

Net production from the Balder, Ringhorne and Ringhorne Øst fields (Kistos 10%, 10% and 7.4%, respectively) in the period averaged 2,800 boepd (H1 2023: 2,200 boepd; H1 2023 pro forma: 1,700 boepd), reflecting the increased number of wells on production compared to the previous period. Production efficiency in the first half of 2024 was 93%, which compares favourably with the 82% achieved in the first half of 2023. 554 kbbl of crude was lifted from the Balder floating production unit (FPU) in the period, comprising one part cargo in a co-lifting with Vår in January under the legacy joint lifting arrangement, and one full cargo (500 kbbl) under the new sales and lifting arrangement that Kistos entered at the start of 2024. The average realised price in the period was $82/bbl (H1 2023: $80/bbl).

Balder Future and other developments

The Balder Future project involves the drilling of 14 new production wells plus one new water injector on the Balder field alongside the refurbishment of the Jotun FPSO, which will be integrated within the Balder Area hub to increase processing and handling capacities across the Balder and Ringhorne fields. The project's target is to extract an additional c.150 mmboe from the area, and to provide future expansion capacity to tie in extra wells to the FPSO after the completion of Balder Future drilling programme.

The Jotun FPSO, which will act as an area hub and enable future growth opportunities, is nearing completion and the mooring system has been re-designed to reduce potential weather constraints for installation. Other elements of the Balder Future project are largely complete. All subsea facilities have been installed and all 14 production wells drilled and completed, while the single water injector well was completed in July.

Nevertheless, in August the operator of Balder Future, Vår Energi, announced that first oil from the project is now anticipated by the end of Q2 2025 rather than by the end of Q4 2024. In reaching the decision to delay start-up, a key consideration was to limit as much as possible the carryover of work on the Jotun FPSO into the offshore installation and start-up phase.

Looking forward, Balder Phase V is progressing, including the drilling of six production wells to utilise the remaining subsea template well slots to capture gross 2P reserves of over 30 mmboe. Drilling of these wells will commence in the first half of 2025 with the COSL Pioneer semi-submersible drilling rig and will be completed in 2026. In addition, the Balder Phase VI project is being matured, with the aim of adding new subsea facilities and wells, with an investment decision expected in the first half of 2025.

UK Storage

In April 2024, Kistos completed the acquisition of EDF's Hill Top Farm and Hole House onshore gas storage assets in Cheshire, UK, for £25 million ($31.1 million) payable in cash at completion (less closing working capital adjustments) (the 'Gas Storage Acquisition'). The Gas Storage Acquisition is in line with the Group's strategy to pursue opportunities that align with the energy transition and provides diversification of the asset portfolio into a stable marketplace that offers significant growth potential.

As purchased, Hill Top's working gas capacity was 17.8 million therms, accounting for 3.1% of the UK's total available onshore gas storage capacity. Due to the fast cycle nature of the facility, Hill Top can deliver up to 11% of the UK's flexible daily gas capacity if called upon.

Following the acquisition, Kistos successfully integrated the existing staff and infrastructure and is working closely with its trading partner to maximise value via the placing of intrinsic seasonal gas trades and opportunistic extrinsic trades that take advantage of gas price volatility.

In the period from acquisition to 30 June, 17.8 million therms were traded for the purpose of intrinsic trades (a combination of seasonal gas trades as well as Operating Margins contract placed with National Gas) whilst 191 million therms of gas were traded for extrinsic benefit, and 71 million therms of gas were physically moved. This represents a significant increase in the level of activity under the previous ownership. Revenue in the period from acquisition to 30 June was $1.9 million. This excludes unrealised gains for intrinsic seasonal trades that have not yet settled.

During May and June, we successfully undertook the fifth and final phase of a 'soft cycling' relaxation trial, the purpose of which was to monitor the integrity of the five caverns at Hill Top Farm during a period where pressure was as close to the original operating design pressure as possible. Following completion of the trial, independent geotechnical experts Geostock Group provided a report that stated the facility can operate as per its original design parameters. This means 4.2 million therms previously categorised as excess cushion gas are now able to be included within the working gas total, representing an uplift of 24% to the working gas volume at Hill Top, therefore increasing the amounts available to be moved and/or traded each day. The benefits of this additional working gas volume (including proceeds from selling this previously trapped cushion gas back to the market) will be seen in the second half of 2024.

We are now evaluating the economics of recommissioning the Hole House facility and expect our evaluation to conclude during the second half of 2024. Hole House, developed specifically for gas storage, was operational from 2001 through to 2018 and requires approximately one-third as much cushion gas as Hill Top for the same amount of working gas. Post-2018 a period of decommissioning the caverns by means of re-brining them commenced and three out of the total four caverns are now nearly all brine filled, with cushion gas sold to market.

Netherlands production

Q10-A

Net Q10-A (Kistos 60% and operator) production in the first half of 2024 was 2,200 boepd compared to 3,100 boepd in the first half of 2023. Production was adversely impacted by an unplanned two-week shutdown caused primarily by the failure of fire water pumps on the TAQA-operated P15-D platform, the start of the planned P15-D annual maintenance turnaround which commenced at the end of June and ongoing natural reservoir decline.

Kistos continues to evaluate opportunities to enhance value from the Q10-A gas field, working closely with the operator and other users of the P15-D platform and associated infrastructure to ensure volumes are maximised and unit operating costs are minimised in the coming years. The objective of this collaborative exercise would be to extend the economic life of the hub for the benefit of all users. Kistos has also reviewed its own underlying cost as an operator of Q10-A and optimisations have been made, including taking a decision to move office in Q3 2024, and reducing head count through synergies realised through integration of our Kistos Energy Norway team into the management of elements of our Dutch business.

Average realised gas prices in the period fell by 35% to €30/MWh from €46/MWh in H1 2023. In conjunction with lower production rates, this caused total revenue in the period to decrease by 52% to $21.0 million compared to $43.4 million in H1 2023.

Orion

The Q10-A Orion oil field (Kistos 60% and operator) is located in the Vlieland sandstone formation, which is a stratigraphically shallower formation deposited above the Q10-A gas field. During the first half of 2024, the second phase of Concept Select continued, with the technical work concluding during Q2 2024. Kistos subsequently received indicative commercial terms from the operator of P15-D and further progress is now awaiting clarity on life extension projects affecting third party infrastructure. These are necessary to ensure Orion will have a viable economic life.

Our team in the Netherlands continues to evaluate opportunities to enhance production from existing wells at Q10-A and to lower costs by working collaboratively with other P15-D users.

M10a/M11

During the first half of 2022, Kistos applied for the M10a and M11 licences (Kistos 60% and operator) north of the Wadden Islands to be extended beyond 30 June 2022. Initially, the extension was denied but during 2023, Kistos successfully appealed against this decision and the licences were re-awarded and extended to 31 August 2028. As part of the licence extension, Kistos was required to apply for a permit to drill an appraisal well prior to 28 February 2024, and to commence operations no later than 31 August 2025.

Following a period of close engagement with local municipalities and other stakeholders in the latter part of 2023, we submitted a request for an extension to the permit application deadline. As this is a request to change the conditions of the licence, the authorities are now formally considering our request. To date, no decision has been made by the authorities and the project therefore remains on hold until such time a response is received.

Other

The Q11-B well, drilled as part of the 2021-22 campaign and suspended in February 2022, continues to be monitored with an annual bubble survey and the next one is anticipated to be undertaken later this year. This offshore testing will confirm the integrity of the well suspension, and an extension to the suspension consent has been received meaning well abandonment will now take place in 2026 at the earliest, a year later than previously indicated.

In January 2023, Kistos was awarded three new offshore exploration licences (P12b, Q13b and Q14), which are adjacent to the existing Q10 block and cover a total of 507 km². Kistos holds a 60% operated working interest in these licences and is partnered with EBN (40%). Initial evaluation of the acreage concluded in H1 2024, and a further desktop work programme was agreed with EBN. Q10-Gamma remains the highest ranked prospect that has been identified in our exploration acreage.

Onshore, after concluding the safe abandonment of three wells (HRK-1, DKK-3 and DKK-4) at the end of 2022, Kistos continued work on the remaining decommissioning activities. This primarily involves removing 19 kilometres of buried pipelines and a trial was conducted during the first quarter of the year that successfully removed sections of pipeline up to 0.4 kilometres at a time, using a new pulling method technique in order to minimise disturbance to landowners and other stakeholders as opposed to the traditional method of open excavation. This enabled the main phase of pipeline removal to commence in June 2024 with a lower budget than initially proposed. We expect the works to conclude by Q3 2025, thus satisfying all our remaining onshore abandonment obligations in the Netherlands.

UK production

Greater Laggan Area

Net production from Kistos' share in the Greater Laggan Area (GLA) (Kistos 20%) in the six months to 30 June 2024 was above expectations at an average rate of 3,400 boepd (H1 2023: 4,300 boepd). The first half of 2024 included a major planned 21-day shutdown of the Shetland Gas Plant (SGP) in May, which was completed safely and on schedule.

Production from the single well on the Edradour field remains suspended. The GLA joint venture continues to monitor the well and its potential restart, but at the present time it is expected to remain offline except for short periods to observe the well's performance.

Average realised gas prices in the period were 72p/therm versus 108p/therm a year earlier. Combined with a 21% reduction in average daily production, this resulted in a 45% decrease in revenue to $35.8 million from $65.6 million in H1 2023.

Following the acquisition of a 4D seismic survey over the GLA fields in 2023, completion of the data processing is now mostly complete, and the joint venture is in the process of performing the interpretation and integration work required to mature further opportunities over the fields. The primary aim of the campaign was to de-risk potential infill drilling opportunities and to provide better reservoir monitoring and management across the GLA as a whole. While the studies and their interpretation are ongoing, initial indications are that there remains potential to drill infill wells on the producing fields.

After further evaluation of the Edradour West development, the partners agreed that, due to reservoir uncertainties, no further work would be undertaken towards its development at the present time. On Glendronach, which previously passed all technical stage gates with the operator and partners, the JV continues to review its development plan and to examine opportunities to reduce costs.

The nearby Victory development (Shell 100%) is planned to be a single subsea well tied back to the existing GLA infrastructure and the SGP, with first gas targeted for the fourth quarter of 2025. The project received regulatory approval to proceed in January 2024 and, once onstream, will significantly reduce unit operating costs for the GLA partners while providing a life extension for the existing GLA fields.

Subsequent to the period end and in partnership with TotalEnergies as operator, Kistos was awarded a 33% interest in seven new blocks or part blocks within the Greater Laggan Area as part of the 33^rd Offshore licencing round. The blocks were previously held by the GLA JV prior to Kistos' acquisition of its 20% non-operated stake from TotalEnergies in 2022. The award of these blocks, which include the previously identified Ballechin exploration prospect, supports the GLA JV partners' efforts to identify opportunities to extend the life of existing infrastructure and maximise economic output. The work programme includes studies on a seismic dataset that is already owned by the JV partners.

Financial Review

Unaudited results for the 6 months ending 30 June 2024

		30 June 2024 (actual)⁶	30 June 2023 (actual)	30 June 2023 (pro forma)⁷
Total production¹	kboe	1,544	1,433	1,659
Production rate¹	boepd	8,400	9,600	9,200
Revenue	$'000	113,328	113,805	129,722
Average realised sales price²	$/boe	65	80	79
Unit opex³	$/boe	29	21	25
Adjusted EBITDA⁴	$'000	48,585	72,220	73,886
(Loss)/profit before tax	$'000	(40,287)	5,281	n/a
Basic earnings per share	$	(0.21)	0.18	n/a
Net cash flow from operations	$'000	(27,351)	102,536	n/a
Unrestricted cash at end of period	$'000	69,950	270,072	270,072
Net debt⁵	$'000	(174,943)	(35,243)	(35,243)

Financial results are prepared in accordance with IFRS, unless otherwise noted below:

1 Total production rate includes gas, oil and natural gas liquids and is rounded to the nearest 100 barrels of oil equivalent per day. 'Actual' production rates include the impact from acquired businesses only from the date of acquisition completion. Sales and production volumes are converted to estimated boe using the conversion factors in Appendix C to the Interim Financial Statements.

2. Non-IFRS measure. Refer to the definition within the glossary.

3. Non-IFRS measure. Refer to the definition within the glossary and reconciliation in Appendix B3.

4. Non-IFRS measure. Refer to the definition within the glossary and reconciliation in note 2.2.1.

5. Non-IFRS measure. Refer to the definition within the glossary and reconciliation in Appendix B2.

6. Actual results for 2024 include revenue and Adjusted EBITDA from the UK Storage segment from the date of the Gas Storage Acquisition (23 April 2024). No pro forma information is provided in respect of the gas storage assets as management consider the pre-acquisition trading result is not representative of future operations: (a) the pre-acquisition trading result in 2024 comprised primarily of the close-out of positions placed by the previous operator in 2023; and (b) the pre-acquisition trading arrangement resulted in a different presentation and accounting treatment of trading activity, which are not comparable to the current activity.

7. Pro forma figures for 2023 include results from Kistos Energy Norway as if it had been acquired on 1 January 2023. The acquisition completed on 23 May 2023

The Group changed its presentation currency from Euros to US Dollars (USD) effective 1 January 2024. The presentation currency has been changed as the Group's debt is now all denominated in USD, and an increasing proportion of the Group's revenues is derived from the sale of crude oil which is priced in USD.

Production and revenue

Actual production on a working interest basis averaged 8,400 boepd in the first half of 2024 (H1 2023: 9,600 boepd reported, 9,200 boepd pro forma). This represents a decrease of 9% (on a pro forma basis) on the equivalent period from a year earlier and reflects the continued natural decline in production from our UK and Dutch producing assets and the planned spring 2024 shutdown of the Shetland Gas Plant, partially offset by a number of new wells coming on-stream in Norway.

The Group's average realised price across gas and oil sales during the period was $65/boe, and total revenue from the sale of our oil and gas production was $113.3 million, compared with $80/boe and $113.8 million reported in H1 2023 (H1 2023 pro forma: $79/boe and $129.7 million), primarily reflecting weaker UK and European gas prices in the current period.

In the Netherlands, the average realised gas price for the period was €30/MWh (H1 2023: €46/MWh). In the UK, the average realised gas price for the period was 72p/therm (H1 2023: 108p/therm). The average realised oil price from crude oil sales in Norway was $82/bbl (H1 2023: $70/bbl), reflecting the norm price differential applied by the Norwegian Petroleum Price Council to Balder crude for the period.

Our gas storage assets contributed $1.9 million of revenue in the period from acquisition, generated from trading activities and one-off sales of excess cushion gas from the currently decommissioned Hole House facility.

Operating costs and unit opex

Unit opex for the period (which excludes non-cash accounting movements in inventory and operating costs from the UK Storage segment) was $29/boe (H1 2023: $21/boe; H1 2023 pro forma: $25/boe), reflecting the impact of decreased productions rates in the UK and Netherlands against broadly flat operating costs.

Adjusted EBITDA

The Group reported Adjusted EBITDA of $48.6 million in the six months to 30 June 2024. The decline versus the comparable period of 2023 was primarily driven by lower gas prices and gas production volumes.

Capital expenditure

Cash capital expenditure in the first half of 2024 was $83.2 million, almost all of which related to the Balder Future project in Norway. It comprised drilling, refurbishment costs on the Jotun FPSO, and other facilities. Most of Kistos' capital expenditure in the second half of the year is also anticipated to be incurred on the Balder Future project in Norway, with no drilling or well intervention campaigns planned in the UK or in the Netherlands. Capital expenditure in Norway is relievable at an effective rate of 78%, with any tax losses generated during the year creating a tax credit that is receivable as a cash tax rebate the following December. The tax receivable in respect of 2023 Norwegian tax losses (primarily generated by capital expenditure in that year) is anticipated to be approximately NOK 901 million ($84.3 million), not including accrued interest, to be received in December 2024. The tax receivable generated by losses incurred in the first half of 2024 is estimated to be NOK 409 million ($38.2 million), to be received in December 2025.

Profit and loss before tax

The statutory operating loss for the period ended 30 June 2024 was $13.1 million (H1 2023: operating loss of $7.7 million). After net finance costs of $27.1 million (2023: net finance income of $2.4 million), principally relating to bond interest expense and foreign exchange movements offset by interest income and a gain on the accounting remeasurement of the Hybrid Bond, a loss before tax of $40.3 million was recorded (H1 2023: loss before tax of $5.3 million).

Tax

The net accounting tax credit for the period was $23.0 million, arising primarily from tax losses generated in Norway and deferred tax movements in the UK. The net current tax charge for the period, (which only reflects tax due or receivable on profits or losses made in the period) was $7.3 million, representing an effective rate of 14% on EBITDA (H1 2023: $19.8 million, and an effective rate of 19% on EBITDA). This reflects the statutory headline rates of 75%, 78% and 50% applicable to oil and gas production activities in the UK, Norway and Netherlands respectively and the statutory headline rate of 25% applicable to onshore UK activities, offset by capital allowances for capital expenditure on the Balder Future project. Cash tax payments for the period were $73 million (H1 2023: $41.2 million), primarily relating to the settlement of our UK tax liabilities on 2022 profits. Due to the significant capital expenditure being incurred on the Balder Future project, tax losses have been generated in Norway. Unlike the UK and Dutch tax regimes, whereby tax losses are carried forward and only offset against any future taxable profits, tax losses in Norway result in cash tax repayments. After receiving NOK 857 million plus interest in December 2023, Kistos expects to receive 901 million NOK ($84.2 million) in December 2024 (in addition to accrued interest).

The current tax liability at 30 June 2024 was $80.5 million (31 December 2023: $142.1 million). Both periods include €47 million ($50.4 million) provided for in respect of the Solidarity Contribution Tax. However, the Group believes the relevant Dutch subsidiary, Kistos NL2 BV, is out of scope (see note 6.3 to the financial statements). This is because, in its opinion, less than 75% of its turnover under Dutch GAAP (the relevant measure for Dutch taxation purposes) was derived from the production of petroleum or natural gas, coal mining, petroleum refining or coke oven products.

Debt and liquidity

Unrestricted cash balances at the end of the period were $70.0 million (31 December 2023: $214.8 million). Net debt at 30 June 2024 was $174.9 million (31 December 2023: $26.8 million). Pre-tax operating cashflow for the period was $45.7 million (H1 2023: $143.7 million), reflecting the decline in average production rates and weaker commodity prices, and favourable working capital movements in the comparative period arising from the settlement of gas sales made in December 2022.

The face value of the Group's bond debt at 30 June 2024 was $289.9 million, comprising USD-denominated bonds issued by its Norwegian subsidiary. $45 million of this is non-interest-bearing, and only fully payable in the event 500,000 bbl (gross) have been offloaded and sold from the Jotun FPSO by 31 December 2024. This amount will decline to $30 million from 1 January 2025 to 28 February 2025, to $15 million from 1 March 2025 to 31 May 2025, and to zero thereafter. The remaining debt comprises a $120 million bond (face value now $128.1 million) and a $105 million bond (face value now $116.8 million). The former matures in September 2026 and carries a coupon of 9.75% (4.5% in cash and 5.25% payment in kind). The latter matures in November 2027 and carries interest at 10.25% wholly payable in kind. Further details on the bonds are outlined in note 5.1 to the financial statements.

The Group has no commodity price hedges in place for the sale of its oil and gas entitlements. Trading activities relating to the Group's gas storage assets are undertaken on the Group's behalf by its third-party trading partner, which also funds and owns the working gas in the caverns. Therefore, the Group has no mark-to-market or margin exposure on trades placed in relation to those activities in the ordinary course of business.

Principal Risks and Uncertainties

The Directors do not believe that the principal risks and uncertainties have changed since the publication of Kistos Holdings plc's 2023 Annual Report dated 10 May 2024. There are a number of potential risks and uncertainties that could have a material impact on the Group's performance over the remaining six months of the financial year and could cause actual results to differ materially from expected and historical results. A detailed explanation of the risks summarised below can be found in the section headed "Principal Risks and Uncertainties" on page 24 of the Kistos Holdings plc 2023 Annual Report dated 10 May 2024, which is available at www.kistosplc.com.

The key headline risks relate to the following:

· Political

· Growth of business and reserves base

· Climate change and energy transition

· Cyber security

· Joint venture activity

· HSE and compliance

· Hydrocarbon production and operational performance

· Project delivery

· Retention of key personnel

· Commodity price

· Liquidity

· Decommissioning costs and timing

· Taxation

Our Environmental, Social and Governance Ambitions

We believe that natural gas and oil have an important role to play in the energy transition, bridging the gap on the journey from fossil fuels to a renewable, zero-carbon future. In the short term, there is unlikely to be sufficient renewable energy to fully meet demand so developing and extracting oil and gas contributes to the security of supply in the meantime. The emissions intensity and the carbon footprint of future projects are actively evaluated, reflected in the decision making related to potential acquisitions and included as part of ongoing operational and project decisions.

The acquisition of onshore gas storage assets in the UK means that we will be able to further contribute to the security of energy supply in the UK. The assets provide around 3% of the UK's total available onshore gas storage capacity and up to 11% of the UK's flexible daily gas capacity if called upon. As well as enhancing Kistos' current place in the traditional energy space, these new assets could be potentially deployed to support the energy transition in the future.

One of Kistos' ESG goals is to achieve carbon neutrality for Scope 1 and Scope 2 emissions by 2030. In the Netherlands, our Scope 1 emissions levels (from our operated assets) are minimal, thanks to the solar panels and wind turbines that power the Q10-A platform, with a Scope 1 emissions intensity level of less than 0.01 kg CO₂e/boe.

Across the Q10-A platform in the Netherlands, as well as our non-operated interests in the GLA offshore the UK and on the NCS, the Group's Scope 1 and Scope 2 emissions intensity ratios are below the North Sea average. They are also estimated to be significantly lower than the average CO₂ emissions intensity associated with the import of liquefied natural gas (LNG), estimated by the North Sea Transition Authority (NSTA) as being 79 kg CO₂/boe[1].

To maintain safe operating conditions on our gas storage site in Cheshire, it is occasionally necessary to vent and purge amounts of natural gas into the atmosphere. In the period from acquisition (23 April 2024) to 30 June 2024, 13 tonnes of natural gas was released because of planned shutdowns and unplanned events (equivalent to approximately 355 tonnes of CO_2, which are classified as Scope 1 emissions)[2]. As the gas storage assets do not produce, nor consume hydrocarbons, we are not required to report emissions associated with this asset within the group's average emissions intensity.

In the 6 months to 30 June 2024, our share of total Scope 1 and 2 emissions were estimated at 20,100 tonnes of CO₂ equivalent (CO₂e). No flaring was undertaken in the current period. The estimated production emissions intensity (which excludes emissions from our gas storage assets, which do not produce hydrocarbons) was 13 kg CO₂e/boe (Scope 1 and 2).

Cautionary Statement About Forward-Looking Statements

This half-year results announcement contains certain forward-looking statements. All statements other than historical facts are forward-looking statements. Examples of forward-looking statements include those regarding the Group's strategy, plans, objectives or future operating or financial performance, reserve and resource estimates, commodity demand and trends in commodity prices, growth opportunities, and any assumptions underlying or relating to any of the foregoing. Words such as 'intend', 'aim', 'project', 'anticipate', 'estimate', 'plan', 'believe', 'expect', 'may', 'should', 'will', 'continue' and similar expressions identify forward-looking statements. Forward-looking statements involve known and unknown risks, uncertainties, assumptions and other factors that are beyond the Group's control. Given these risks, uncertainties and assumptions, actual results could differ materially from any future results expressed or implied by these forward-looking statements, which speak only at the date of this report. Important factors that could cause actual results to differ from those in the forward-looking statements include: global economic conditions, demand, supply and prices for oil, gas and other long-term commodity price assumptions (as they materially affect the timing and feasibility of future projects and developments), trends in the oil and gas sector and conditions of the international markets, the effect of currency exchange rates on commodity prices and operating costs, the availability and costs associated with production inputs and labour, operating or technical difficulties in connection with production or development activities, employee relations, litigation, and actions and activities of governmental authorities, including changes in laws, regulations or taxation. Except as required by applicable law, rule or regulation, the Group does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Past performance cannot be relied on as a guide to future performance.

Interim Financial Statements (unaudited)

Condensed consolidated income statement

$'000	Note	6 months ended 30 June 2024	6 months ended 30 June 2023 (restated)
Revenue	2.1	113,328	113,805
Other income		196	28
Exploration expenses		(481)	(278)
Production and operating costs		(54,601)	(35,984)
Development expenses		(154)	(413)
Abandonment expenses		(1,794)	-
General and administrative expenses		(8,894)	(5,791)
Depreciation and amortisation	2.3, 2.4	(60,611)	(50,426)
Impairment	2.4	(132)	(32,231)
Release of contingent consideration	7.1	-	3,568
Operating loss		(13,143)	(7,722)
Interest income	3.2	4,092	2,846
Interest expenses	3.2	(19,499)	(4,098)
Foreign exchange movements and other net finance costs	3.2	(11,737)	3,693
Net finance (costs)/income		(27,144)	2,441
Loss before tax		(40,287)	(5,281)
Tax credit	6.1	23,045	19,784
(Loss)/Profit for the period		(17,242)	14,503

Basic (loss)/earnings per share ($)	3.1	(0.21)	0.18
Diluted (loss)/earnings per share ($)	3.1	(0.21)	0.17

Condensed consolidated statement of other comprehensive income

$'000	6 months ended 30 June 2024	6 months ended 30 June 2023 (restated)
(Loss)/profit for the period	(17,242)	14,503
Items that may be reclassified to profit or loss:
Foreign currency translation differences	(2,443)	1,632
Total comprehensive (loss)/income for the period	(19,685)	16,135

Condensed consolidated balance sheet

$'000	Note	30 June 2024	31 December 2023 (restated)	31 December 2022 (restated)
Non-current assets
Goodwill	2.4	51,984	54,239	11,642
Intangible assets	2.4	33,748	34,591	46,446
Property, plant and equipment	2.3	523,590	455,286	302,399
Non-current tax receivable	6.2.1	38,237	-	-
Deferred tax assets		6,199	2,133	606
Investment in associates		65	65	65
Other long-term receivables		171	165	109
		653,994	546,479	361,267
Current assets
Inventories		17,952	22,544	10,373
Trade and other receivables	4.2	27,894	29,215	58,463
Current tax receivable	6.2.1	84,248	88,690	-
Cash and cash equivalents	4.1	72,007	214,974	226,896
		202,101	355,423	295,732
Total assets		856,095	901,902	656,999
Equity
Share capital and share premium		9,979	9,979	9,979
Other equity		3,897	3,897	-
Other reserves		72,299	74,714	71,492
(Accumulated loss)/retained earnings		(15,331)	1,911	28,504
Total equity		70,844	90,501	109,975
Non-current liabilities
Abandonment provision	2.5	258,706	231,283	132,239
Bond debt	5.1	236,877	237,936	86,473
Deferred tax liabilities		152,604	144,146	126,687
Other non-current liabilities	4.4	5,695	678	4,495
		653,882	614,043	349,894
Current liabilities
Trade payables and accruals	4.3	35,077	44,477	22,821
Other current liabilities	4.4	14,100	6,152	18,321
Current tax payable	6.2.2	80,474	142,125	153,222
Abandonment provision	2.5	1,718	4,604	2,766
		131,369	197,358	197,130
Total liabilities		785,251	811,401	547,024
Total equity and liabilities		856,095	901,902	656,999

Condensed consolidated statement of changes in equity

$'000	Share capital and share premium	Other equity	Other reserves	Retained earnings	Total equity
At 1 January 2023 (restated)	9,979	-	71,492	28,504	109,975
Profit for the period	-	-	-	14,503	14,503
Movement in the period	-	-	1,632	-	1,632
Total comprehensive income for the period	-	-	1,632	14,503	16,135
Share-based payments	-	-	111	-	111
Issue of warrants	-	3,897	-	-	3,897
At 30 June 2023 (restated)	9,979	3,897	73,235	43,007	130,118

At 1 January 2024 (restated)	9,979	3,897	74,714	1,911	90,501
Loss for the period	-	-	-	(17,242)	(17,242)
Movement in the period	-	-	(2,443)	-	(2,443)
Total comprehensive loss for the period	-	-	(2,443)	(17,242)	(19,685)
Share-based payments	-	-	28	-	28
At 30 June 2024	9,979	3,897	72,299	(15,331)	70,844

Condensed consolidated cash flow statement

$'000	Note	6 months ended 30 June 2024	6 months ended 30 June 2023 (restated)
Cash flows from operating activities:
(Loss)/profit for the period		(17,242)	14,503
Tax credit	6.1	(23,045)	(19,784)
Net finance costs/(income)	3.2	27,144	(2,441)
Depreciation and amortisation	2.3, 2.4	60,611	50,426
Impairment	2.4	132	32,231
Change in fair value and releases of contingent consideration		-	(3,568)
Share-based payment expense		28	111
Income tax paid		(73,011)	(41,199)
Interest income received		1,789	2,838
Abandonment costs paid		(757)	(29)
Decrease in trade and other receivables		3,543	17,460
(Decrease)/increase in trade and other payables		(11,518)	44,875
Decrease in inventories		4,975	7,142
Net movement in other working capital items		-	(29)
Net cash flow from operating activities		(27,351)	102,536
Cash flows from investing activities:
Payments to acquire tangible and intangible fixed assets		(83,164)	(49,816)
Consideration paid for Gas Storage Acquisition, net of cash acquired	2.7	(22,070)	-
Net cash acquired in Mime Acquisition		-	7,802
Contingent consideration paid for GLA Acquisition		-	(17,231)
Net cash flow from investing activities		(105,234)	(59,245)
Cash flows from financing activities:
Interest paid		(3,447)	(5,141)
Lease repayments and other financing cash flows		(1,760)	(1,227)
Net cash flow from financing activities		(5,207)	(6,368)
(Decrease)/increase in cash and cash equivalents		(137,792)	36,923
Cash and cash equivalents at beginning of period		214,974	226,896
Effects of foreign exchange rate changes		(5,175)	6,253
Cash and cash equivalents at end of period		72,007	270,072

Notes to the interim condensed consolidated financial statements

Section 1 General information and basis of preparation

1.1 General information

These condensed consolidated financial statements for the six-month period ended 30 June 2024 have been prepared in accordance with IAS 34 Interim Financial Reporting and AIM Rule 18. These condensed consolidated financial statements, along with the management report above, represent a 'half-yearly report' as referred to in the AIM Rules. Accordingly, they do not include all the information required for a full annual financial report. These condensed consolidated financial statements are unaudited and do not constitute statutory accounts as defined in section 434 of the Companies Act 2006 and should be read in conjunction with the 2023 Annual Report and Accounts. Interim period results are not necessarily indicative of results of operations or cash flows for an annual period. The condensed consolidated financial statements have not been subject to review or audit by independent auditors; therefore, all figures are unaudited (unless otherwise stated). The Group's business is not inherently seasonal, but gas prices (and therefore revenue from gas sales) are typically higher in the European winter months than the summer.

These condensed consolidated financial statements were authorised for issue by Kistos Holdings plc's Board of Directors on 25 September 2024.

1.2 Going concern

These condensed consolidated financial statements have been prepared in accordance with the going concern basis of accounting. The forecasts and projections made in adopting the going concern basis take into account forecasts of commodity prices, production rates, operating and general and administrative (G&A) expenditure, committed and sanctioned capital expenditure, and the timing and quantum of future tax payments. To assess the Group's ability to continue as a going concern, management evaluated cash flow forecasts for the period to December 2025 (the going concern period) by preparing a base case forecast and various downside sensitivities. The base case assumed the following:

· First oil from the Jotun FPSO in mid-2025 in line with the latest update provided by the operator (note 2), resulting in the entire $45 million Hybrid Bond being cancelled.

· Q10-A production in line with latest internal forecasts.

· Production from the GLA and Balder/Ringhorne in line with latest available operator forecasts and, in the case of the latter, taking into account the first oil date from the Jotun FPSO as noted above.

· Committed and contracted capital expenditure only (being primarily the Group's share of Balder Future capital expenditure) in line with currently approved budgets and authorities for Expenditure (AFEs).

· A tax rebate of NOK901 million (excluding interest) is received in December 2024 in respect of Norwegian tax losses incurred in 2023, and a further rebate is received in December 2025

· Obligations under Decommissioning Security Agreements (DSAs) for the GLA fields are satisfied in full by the purchase of surety bonds during the period covered by the going concern assessment.

· Ongoing cash flows from the Gas Storage Acquisition in line with existing budgets and conservative estimates from profits arising from gas trading activities.

· The Solidarity Contribution Tax Charge and accrued interest (should it be paid), will occur outside of the going concern period.

· Commodity prices based on forward curves prevailing at the date of assessment (being an average of 103p/therm, €41/MWh and $75/bbl across the going concern period)

The base case forecast indicated that the Group would be able to maintain sufficient liquidity to meet its bond covenant requirement (being a minimum liquidity of $10 million to be held within Kistos Energy Norway) and day-to-day operations across the going concern period.

As part of the assessment, reasonably plausible scenarios were also prepared and analysed. These include:

· a reduction to the oil and gas price assumptions based on recent price volatility;

· a reduction to forecast production rates based on reasonably plausible changes to technical assumptions and sensitivities to extending the impact of planned maintenance shut-ins; and

· adverse movement in foreign exchange rates.

The outcome of applying one or more of these reasonably plausible downside scenarios against the base case supported the going concern conclusion.

A key assumption within the base case is the timing of any payment under the Solidarity Contribution Tax Charge, for which the Group holds a provision of €47 million ($50.4 million). A return in respect of this tax was filed by the required deadline of 31 May 2024. As set out in note 6.3, the Group believes that Kistos NL2 B.V. is out of scope of this charge in which case no tax would be payable. In the event the tax is payable, based on legal and tax advice received, the Group is of the opinion that a cash outflow is likely to occur outside the going concern period, and after procedures, including re-assessments, objections, court hearings and appeals, had been exhausted. However, as there is no precedent for the payment, collection, or appeal of this tax, should the Belastingdienst (Dutch Tax Authority) demand an earlier payment, or require payment prior to any appeal being admitted, this would have a material adverse effect on the Group's liquidity.

The other key assumption is the continued availability of surety bonds used to cover obligations under Decommissioning Security Agreements (DSAs). The obligation for the GLA assets in respect of 2024 was £69 million ($88 million), which the Group satisfied via the purchase of surety bonds at an approximate cost of $3 million. The redetermination in respect of 2025, subject to final agreement by the JV partners, is an obligation of £63 million ($80 million), with renewed surety bonds (or other arrangements, if applicable) to be put in place by the end of 2024. As part of the going concern assessment the Directors sought advice from surety bond brokers and other advisors regarding the Group's ability to cover the 2025 obligation fully via surety bonds given current market conditions and the risk appetite of insurance providers. If the bonds are not able to be renewed in full or part, the Group would likely have to satisfy the obligations by lodging cash security in full or part, significantly reducing available liquidity. Based on the advice received and status of discussions with surety and other insurance providers, the Directors are of the view that the Group will be able to meet the current DSA provisions and those required in the foreseeable future.

Based on the assessments made, an adverse movement in either of these key assumptions could result in the Group breaching its liquidity covenant in mid-2025. The Group has considered mitigating actions it would take in the event there was a cash shortfall. The Group is of the opinion that it would firstly manage its liquidity position and avoid any breach via temporary working capital management activities to cover the period of adverse liquidity. Should any shortfall not be managed via temporary working capital management, the main potential sources of finance available to the Group include undertaking a tap issue of the KENO02 bond (see note 5.1), for which up to $60 million is available, securing another financing facility, and/or equity financing. A tap issue of the KENO02 bond would require the consent of two-thirds of bondholders represented at a bondholders meeting, although there is no guarantee all, if any, of the additional bonds would be taken up by bondholders (even if consent was granted). The Group has arranged a short-term unsecured financing facility for up to $15 million which is available to be drawn down until the end of 2024. This facility will enable to the Group to meet any short-term liquidity pressures that may arise from adverse movements to production rates, commodity prices and/or increases to capital expenditure in the intervening period prior to the Norwegian tax rebate being received in December 2024. The Group is of the view that the facility's availability could be extended into 2025, although this is subject to agreement with the financing provider. In respect of an equity raise, while the Group and its Board have a strong track record in raising funds via equity for Kistos and previous vehicles, raising equity financing is outside of managements control.

These condensed consolidated financial statements do not include any adjustments that may result from the outcome of these uncertainties.

1.3 Material accounting policies

The material accounting policies used in these condensed consolidated financial statements are consistent with those used in the Group's annual financial statements for the year ended 31 December 2023, with the exception of a change to the presentation currency of the Group's financial statements (note 1.4) and new material accounting policies outlined below which have been introduced following the Gas Storage Acquisition:

Property, plant and equipment

Cushion gas, being that volume of gas that cannot be withdrawn from gas storage caverns while they remain in use, is classified within 'Property, plant and equipment' and is not depreciated.

Freehold land is held at cost and is not depreciated.

Certain amended accounting standards and interpretations became applicable for the current reporting period. The Group did not have to change its accounting policies or make retrospective adjustments as a result of adopting these amendments, as the Group's accounting policies are already aligned with the amended standards, or they are not relevant to the Group's business. There are new and revised accounting standards in issue that will become effective for future periods, but it is not expected these standards and interpretations will have a material impact on the Group's financial statements upon adoption.

Other minor reclassifications have been made to the presentation of certain line items in the comparative financial statements and the notes in line with the presentation within the 2023 annual financial statements:

· On the consolidated cash flow statement, interest income received is now presented within 'Net cash flow from operating activities' (previously within 'Net cash flow from financing activities').

· On the consolidated balance sheet, balances relating to amounts due to joint operators are presented within 'Trade payables and accruals' (previously within 'Other liabilities').

In preparing these condensed consolidated financial statements, management has made judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates. The significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those that applied to the audited annual financial statements at 31 December 2023, with the addition of a critical judgement that applied in accounting for the Gas Storage Acquisition:

· As substantially all the fair value of the gross assets acquired in the Gas Storage Acquisition was concentrated in a group of similar identifiable assets, the 'concentration test' provisions of IFRS 3 Business Combinations were met;

· Presumption of going concern

· Estimate of abandonment provisions

· Estimation of reserves and contingent resources

· Assessment of capitalised borrowing costs

· Identification of impairment indicators

· Accounting treatment of the Hybrid Bond

· Recognition of Solidarity Contribution Tax provision

1.4 Foreign currencies and translation

Items included in the financial statements of each of the Group's entities are measured using the currency of the primary economic environment in which each entity operates (the functional currency). Transactions in currencies other than the functional currency are translated to the entity's functional currency at the foreign exchange rates at the date of the transactions.

Foreign exchange gains and losses resulting from the settlement of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement. All UK-incorporated entities in the Group, including Kistos Holdings plc, have a functional currency of pounds Sterling (GBP). All Dutch-incorporated entities have a functional currency of euros (EUR). Norwegian-incorporated entities have a functional currency of Norwegian Krone (NOK).

The Group changed its presentation currency from Euros (EUR) to US Dollars (USD) effective 1 January 2024. The presentation currency has been changed as the Group's debt is now all denominated in USD, and an increasing proportion of the Group's revenues is derived from the sale of crude oil which is priced in USD.

A change in presentation currency represents a change in accounting policy under IAS 8 'Accounting Policies, Changes in Accounting Estimates and Errors' and therefore requires the restatement of comparative financial information.

The results and balance sheet of all the Group entities that have a functional currency different from the presentation currency were translated into the presentation currency as follows:

· Assets and liabilities for each balance sheet presented were translated at the closing rate at the date of that balance sheet (except for certain items in equity which are translated at the historical rate);

· Income and expenditure and cash flows were translated at average exchange rates for the periods; and

· The effects of translating the Group's financial results and financial positions into USD was recognised within 'Other comprehensive income' and against the foreign currency translation reserve (within 'Other reserves' on the balance sheet).

1.5 Significant events in the current period

The financial position and performance of the Group was affected by the following events and transactions during the six months ended 30 June 2024:

· Based on a preliminary assessment, the acquisition of EDF Energy (Gas Storage) Limited in April 2024 resulted in the recognition of, inter alia, $69.0 million of property plant and equipment and a net cash outflow of $22.1 million in respect of the transaction itself.

· Cash outflows of $73.0 million in respect of tax liabilities.

Section 2 Oil and gas operations

2.1 Revenue

$'000		6 months ended 30 June 2024
	Netherlands Production	Norway Production	UK Production	UK Storage	Total

Sales of produced natural gas	21,039	-	28,394	1,912	51,345
Sales of produced hydrocarbon liquids	-	54,544	7,439	-	61,983
Revenue from external customers	21,039	54,544	35,833	1,912	113,328

3$'000	6 months ended 30 June 2023
	Netherlands Production	Norway Production	UK Production	Total

Sales of crude oil and liquids	-	4,881	11,893	16,774
Sales of natural gas	43,366	-	53,665	97,031
Revenue from external customers	43,366	4,881	65,558	113,805

2.2 Segmental information

The performance of the Group is monitored by the Executive Directors (comprising the Executive Chairman, Chief Executive Officer and Chief Financial Officer) who consider the business from both a product and a geographic perspective.

2.2.1 Adjusted EBITDA

The Executive Directors use Adjusted EBITDA as a measure of profit and loss to assess the performance of the operating segments. Adjusted EBITDA is a non-IFRS measure, which management believe is a useful metric as it provides additional useful information on performance and trends. Adjusted EBITDA is not defined in IFRS or other accounting standards, and therefore may not be comparable with similarly described or defined measures reported by other companies. It is not intended to be a substitute for, or superior to, any nearest equivalent IFRS measure.

Adjusted EBITDA excludes the effects of significant items of income and expenditure that may have an impact on the quality of earnings such as impairment charges, other non-cash charges such as depreciation and share-based payment expense, transaction costs, changes in contingent consideration relating to business acquisitions and development expenditure.

A reconciliation of Adjusted EBITDA by segment to profit before tax, the nearest equivalent IFRS measure, is presented below.

$'000	Note	6 months ended 30 June 2024	6 months ended 30 June 2023 (restated)
Adjusted EBITDA by segment:
Netherlands Production		12,855	33,212
Norway Production		26,401	1,750
UK Production		13,632	40,110
UK Storage		(1,873)	-
All other segments		(2,430)	(2,852)
Group Adjusted EBITDA		48,585	72,220
Development expenses		(154)	(413)
Share-based payment expense		(29)	(111)
Depreciation and amortisation	2.3, 2.4	(60,611)	(50,426)
Impairment	2.4	(132)	(32,231)
Transaction costs		(802)	(329)
Change in fair value and releases of contingent consideration	7.1	-	3,568
Operating loss		(13,143)	(7,722)
Net finance (costs)/income	3.2	(27,144)	2,441
Loss before tax		(40,287)	(5,281)

2.3 Property, plant and equipment

$'000	Freehold land	Oil and gas production assets	Gas storage facilities and other	Total
Cost
At 1 January 2024 (restated)	-	739,848	2,483	742,331
Acquisitions (note 2.7)	2,091	-	66,467	68,558
Additions	-	86,810	1,121	87,931
Foreign exchange differences	8	(37,862)	538	(37,316)
At 30 June 2024	2,099	788,796	70,609	861,504

Accumulated depreciation and impairment
At 1 January 2024 (restated)	-	(286,170)	(875)	(287,045)
Depreciation charge for period	-	(59,923)	(453)	(60,376)
Foreign exchange differences and other movements	-	9,485	22	9,507
At 30 June 2024	-	(336,608)	(1,306)	(337,914)

Net book value at 31 December 2023 (restated)	-	453,678	1,608	455,286
Net book value at 30 June 2024	2,099	452,188	69,303	523,590

Due to the nature of the Group's oil and gas development projects it is not practical to ascertain the carrying amount of expenditure that is under construction.

2.4 Intangible assets and goodwill

$'000	Goodwill	Exploration and evaluation assets	Other	Total
Cost
At 1 January 2024 (restated)	58,058	129,600	754	188,412
Acquisitions (note 2.7)	-	-	-	-
Additions	-	104	147	251
Foreign exchange differences and other movements	(2,281)	(2,495)	(22)	(4,798)
At 30 June 2024	55,777	127,209	879	183,865

Accumulated amortisation and impairment
At 1 January 2024 (restated)	(3,819)	(95,534)	(229)	(99,582)
Amortisation charge for the period	-	-	(235)	(235)
Foreign exchange differences and other movements	26	1,750	40	1,816
Impairment and write-off of exploration assets	-	14	(146)	(132)
At 30 June 2024	(3,793)	(93,770)	(570)	(98,133)

Net book value at 31 December 2023 (restated)	54,239	34,066	525	88,830
Net book value at 30 June 2023	51,984	33,439	309	85,732

Exploration and evaluation assets include the exploration licence portfolio acquired as part of the GLA Acquisition, the Orion oil prospect on the Q10-A licence and exploration prospects in Norway. The Group's oil and gas licence interests are shown in note 2.6. Exploration write-offs in the period relate to additional residual costs incurred in the period on the Benriach licence, which was deemed sub-commercial following evaluation of drilling results in 2023.

2.5 Abandonment provision

$'000	Note	6 months ended 30 June 2024

At 1 January 2024 (restated)		235,887
Acquisitions	2.7	30,627
Accretion expense	3.2	4,511
Changes in estimates to provisions		1,408
Utilisation of provisions		(757)
Effect of changes to discount rate		(3,976)
Foreign exchange differences		(7,276)
At 30 June 2024		(260,424)
Of which:
Current		1,718
Non-current		258,706
Total		260,424

Abandonment provisions primarily include:

· In the Netherlands, the Group's share of the estimated cost of abandoning the producing Q10-A wells, decommissioning the associated infrastructure, plugging and abandoning the currently suspended Q11-B well, and removal and restoration of certain onshore pipelines and corresponding land from historic assets. Abandonment of the producing wells and infrastructure is expected to take place between five and eight years from the balance sheet date, in 2026 for the Q11-B well and within one year for the onshore pipelines and land restoration.

· In the UK Production segment, the Group's share of the estimated cost of plugging and abandoning the producing and suspended Laggan, Tormore, Edradour and Glenlivet wells, removal of the associated subsea infrastructure, and demolition of the SGP and restoration of the land upon which the plant is constructed. Abandonment is expected to take place between five and fourteen years from the balance sheet date, subject to production and commodity price forecasts and level of use of the SGP by third parties.

· In Norway, plugging and abandonment of drilled wells on Ringhorne and Balder, and removal of the Balder FPU and Ringhorne platform. Abandonment is expected to take place in approximately 25 years' time.

· In the UK Storage segment, the re-brining of gas storage caverns and decommissioning of gas storage plant assets. Abandonment is expected to take place in approximately 20 years' time.

Abandonment provisions are initially estimated in nominal terms, based on management's assessment of publicly available economic forecasts and determined using inflation rates of 2.25% to 2.50% (2023: 2.0% to 2.5%) and a discount rate of 2.73% to 4.14% (2023: 2.2% to 3.8%). The changes in estimates to provisions arise primarily as a result of the increased inflation rate assumed in certain regions.

The Group has in issue £69 million ($88 million) of surety bonds as at 30 June 2024 and 31 December 2023 to cover its obligations under Decommissioning Security Agreements (DSAs) for the GLA fields and infrastructure. The amount of the bonds required is re-assessed each year, changing in line with estimated post-tax cash flows from the assets, revisions to the abandonment cost, inflation rates, discount rates and other inputs defined in the DSAs.

The Group is obliged to deposit to Vår Energi a post-tax amount of $12.7 million (plus interest accruing at SOFR +3%), payable three months after the date of the first oil produced from the Balder and Ringhorne fields over the Jotun FPSO. Based on current estimates of interest rates and expected timing of Balder first oil, the amount to be deposited is anticipated to be approximately $16 million. This amount will be repaid to the Group upon final decommissioning of the fields.

2.6 Joint arrangements and licence interests

As at the balance sheet date, the Group has the following interests in joint arrangements that management has assessed as being joint operations.

The operator of the licences held by Kistos Energy Limited is TotalEnergies E&P UK Limited. The operator of the licences held by Kistos Energy (Norway) AS is Vår Energi ASA.

Except where otherwise noted, the interest and status of licences is the same as at the end of the prior period.

Field or licence	Country	Licence holder	Licence type	Status	Interest at 30 June 2024
M10a & M11¹	Netherlands	Kistos NL1 B.V.	Exploration	Operated	60%
Donkerbroek	Netherlands	Kistos NL1 B.V.	Production	Operated	60%
Donkerbroek-West	Netherlands	Kistos NL1 B.V.	Production	Operated	60%
Akkrum-11	Netherlands	Kistos NL1 B.V.	Production	Operated	60%
Q07	Netherlands	Kistos NL2 B.V.	Production	Operated	60%
Q08	Netherlands	Kistos NL2 B.V.	Exploration	Operated	60%
Q10-A	Netherlands	Kistos NL2 B.V.	Production	Operated	60%
Q10-B	Netherlands	Kistos NL2 B.V.	Exploration	Operated	60%
Q11	Netherlands	Kistos NL2 B.V.	Exploration	Operated	60%
P12b²	Netherlands	Kistos NL2 B.V.	Exploration	Operated	60%
Q13b²	Netherlands	Kistos NL2 B.V.	Exploration	Operated	60%
Q14²	Netherlands	Kistos NL2 B.V.	Exploration	Operated	60%
P911, P1159, P1195, P1453³ and P1678 (Laggan, Tormore, Edradour and Glenlivet)	UK	Kistos Energy Limited	Production	Non-operated	20%
P2411 and P1453² (Benriach)	UK	Kistos Energy Limited	Exploration	Non-operated	25%
P2594 (Cardhu)	UK	Kistos Energy Limited	Exploration	Non-operated	20%
P2604 (Roseisle)	UK	Kistos Energy Limited	Exploration	Non-operated	14%
PL001	Norway	Kistos Energy (Norway) AS	Production	Non-operated	10%
PL027⁴	Norway	Kistos Energy (Norway) AS	Production	Non-operated	10%⁵
PL027C	Norway	Kistos Energy (Norway) AS	Production	Non-operated	10%
PL027HS	Norway	Kistos Energy (Norway) AS	Production	Non-operated	10%
PL028	Norway	Kistos Energy (Norway) AS	Production	Non-operated	10%
PL028S	Norway	Kistos Energy (Norway) AS	Production	Non-operated	10%

¹ Following successful appeal against non-renewal (decision received in July 2023), the licence was re-awarded to Kistos retroactively from 30 June 2022.

² Acquired or awarded during the current period.

³ Licence P1453 is split into the portion including and excluding the Benriach area.

⁴ Licence 027 comprises Balder and Ringhorne Øst fields. Kistos' share of the Ringhorne Øst unit is 7.4%.

2.7 Acquisitions

On 23 April 2024, the Group acquired 100% of the share capital of EDF Energy (Gas Storage) Limited (subsequently renamed Kistos Energy Storage Limited) from EDF Energy (Thermal Generation) Limited for cash consideration of £25 million ($31.1 million) less closing working capital adjustments (the 'Gas Storage Acquisition'). The main assets acquired in the transaction comprise two gas storage facilities onshore in the UK, Hill Top Farm ('Hill Top') and Hole House Farm ('Hole House') which has a total current working volume of up to 21.2 million therms.

The acquisition was accounted for as an acquisition of a group of assets as substantially all the fair value of the gross assets acquired was concentrated in a group of similar identifiable net assets (and therefore the 'concentration test' provisions of IFRS 3 'Business Combinations' was met).

No goodwill or bargain purchase was recognised as the transaction was accounted for as an asset acquisition and not a business combination. Directly attributable acquisition-related costs were not capitalised as part of the transaction as they were not considered to be material.

Section 3 Income statement

3.1 Earnings per share

	6 months ended 30 June 2024	6 months ended 30 June 2023 (restated)
Consolidated [loss/profit] for the period, attributable to shareholders of the Group ($'000)		14,503
Weighted average number of shares used in calculating basic earnings per share	82,863,743	82,863,743
Potential dilutive effect of:
Employee share options	-	26,752
Weighted average number of ordinary shares and potential ordinary shares used in calculating diluted earnings per share	82,863,743	82,890,495

Basic (loss)/earnings per share ($)	(0.21)	0.18
Diluted (loss)/earnings per share ($)	(0.21)	0.17

3.2 Net finance costs

$'000	Note	6 months ended 30 June 2024	6 months ended 30 June 2023 (restated)
Bank interest income		1,789	2,846
Interest on tax receivable		2,295	-
Other interest income		8	-
Total interest income		4,092	2,846
Bond interest		(17,302)	(1,911)
Other interest		-	(22)
Interest on tax payable		(628)	(1,680)
Surety bond costs		(1,569)	(485)
Total interest expenses		(19,499)	(4,098)
Accretion expense on abandonment provisions and other liabilities	2.5	(4,511)	(2,453)
Accretion expense on lease liabilities		(76)	(57)
Remeasurement gain on Hybrid Bond	5.1	7,792	1,329
Amortisation of bond costs		-	(553)
Net foreign exchange (losses)/gains		(14,942)	5,427
Total other net finance (costs)/income		(11,737)	3,693
Total net finance (costs)/income		(27,144)	2,441

Section 4 Working capital

4.1 Cash and cash equivalents

Cash and cash equivalents consist of cash at bank, short-term deposits and restricted cash. Restricted cash includes deposits lodged for office leases, employee withholding taxes in Norway, and cash lodged as letters of credit under gas storage capacity arrangements. Financial covenants relating to minimum liquidity balances are disclosed in note 5.1.1.

$'000	30 June 2024	31 December 2023 (restated)
Cash at bank and short-term deposits	69,950	214,789
Restricted cash	2,057	185
	72,007	214,974

4.2 Trade and other receivables

$'000	30 June 2024	31 December 2023 (restated)
Trade receivables	4,158	9,142
Accrued income	10,849	9,819
Receivables due from joint operation partner	900	653
Other receivables and cash overcalls	5,771	1,996
Prepayments	4,772	6,916
VAT receivable	1,444	689
Total trade and other receivables	27,894	29,215

Accrued income represents amounts due in respect of hydrocarbon sales and gas storage capacity revenue that had not been invoiced at the balance sheet date. All hydrocarbon sales accrued income had been invoiced and collected in full within one month of the corresponding reporting date. Certain amounts relating to gas storage capacity revenue are contractually due to be collected in the second quarter of 2025.

4.3 Trade payables and accruals

$'000	30 June 2024	31 December 2023 (restated)
Trade payables	4,423	6,822
Payables to joint operators	3,209	2,881
Accruals	27,445	34,774
Total trade payables and accruals	35,077	44,477

Trade payables are unsecured and generally paid within 30 days. Accrued expenses are also unsecured and represents estimates of expenses incurred but where no invoice has yet been received, and amounts accrued by joint operators but not yet billed. The carrying value of trade payables and other accrued expenses are considered to be fair value given their short-term nature.

4.4 Other liabilities

$'000	30 June 2024	31 December 2023 (restated)
Bond interest payable	7,030	1,071
Salary and payroll-related liabilities	1,168	1,083
Lease liabilities	680	326
VAT payable	136	685
Overlift	3,256	1,671
Other	1,830	1,316
Other liabilities - current	14,100	6,152

Lease liabilities	5,695	678
Other liabilities - non-current	5,695	678

Lease liabilities include leasehold land and subterranean caverns acquired as part of the Gas Storage Acquisition.

Section 5 Capital and debt

5.1 Bond debt

$'000			Total
At 1 January 2024 (restated)			237,936
Issue of new bonds via payment-in-kind interest			3,991
Interest expense			2,593
Remeasurement of Hybrid Bond			(7,792)
Net foreign exchange gains and other movements			149
At 30 June 2024			236,877

Details of the bonds outstanding are as follows:

					30 June 2024		31 December 2023 (restated)
Bond	Issuer	Denomination	Nominal interest rate	Maturity date	Face value $'000	Carrying amount $'000	Face value $'000	Carrying amount $'000
KENO01	Kistos Energy (Norway) AS	USD	10.25%¹	November 2027	116,809	101,817	116,809	99,990
KENO02	Kistos Energy (Norway) AS	USD	9.75%²	September 2026	128,084	126,060	124,787	122,213
Hybrid Bond	Kistos Energy (Norway) AS	USD	n/a	March 2083³	45,000	9,000	45,000	15,733
Total					289,893	236,877	286,596	237,936

1. Interest payable wholly in kind via issuance of new bonds.

2. Interest payable partly in cash (4.5%) and partly in kind via issuance of new bonds (5.25%).

3. Certain amounts of the Hybrid Bonds will be cancelled for nil consideration should offload and sales thresholds related to the Jotun FPSO are not met, starting 31 December 2024. In a situation where no crude oil has been lifted and sold from the Jotun FPSO by 31 May 2025, all outstanding Hybrid Bonds will be cancelled.

The Group has call options to redeem bonds as follows:

Bond	Call price	Period of call option
KENO01¹	100%	From full discharge/redemption of KENO02 until maturity
KENO02¹	100%	Anytime until maturity
Hybrid Bond¹	100%	From full discharge/redemption of both KENO01 and KENO02 until maturity

1. Must be called in full, not in part.

5.1.1 Financial covenants

Under terms of the KENO01 and KENO02 bonds, Kistos Energy (Norway) AS (as issuer) is required to maintain a minimum liquidity of $10 million until such time as the Balder and Ringhorne fields have achieved 90 days of oil production at an average rate of at least 75,000 barrels of oil per day (gross). The issuer complied with the financial covenant at all times in the current period.

Section 6 Tax

6.1 Tax credit or charge for period

$'000	6 months ended 30 June 2024	6 months ended 30 June 2023 (restated)
Current tax charge	7,269	13,730
Deferred tax credit	(30,314)	(33,514)
Total tax credit for the period	(23,045)	(19,784)

6.2 Current tax

6.2.1 Current tax receivable

The Group has a tax receivable of $122.4 million, $84.2 million of which is due to be received in cash by the Group in December 2024 and $38.2 million is due to be received in cash in December 2025. The current tax assets relate to tax losses generated in Norway and accrue repayment interest from 1 January 2024 and 1 January 2025 respectively (the current statutory rate being 4.5%).

6.2.2 Current tax payable

The Group has current tax liabilities by segment as follows:

$'000	30 June 2024	31 December 2023 (restated)
Netherlands Production	53,478	55,090
Norway Production	-	-
UK Production	21,095	87,035
UK Storage	5,901	-
	80,474	142,125

Current tax liabilities are anticipated to be settled within one year of the balance sheet date, except €47 million ($50.4 million) relating the Solidarity Contribution Tax (note 6.3) in the Netherlands Production segment, for which the timing of settlement is uncertain.

Late or underpaid tax accrues interest at a rate of at least 6.25% in the UK and 10% in the Netherlands. $0.6 million of late payment interest was charged in the current period.

6.3 Uncertain tax positions

In October 2022, the EU member states adopted Council Regulation (EU) 1854/2022, which required EU member states to introduce a Solidarity Contribution Tax for companies active in the oil, gas, coal and refinery sectors. The Dutch implementation of this solidarity contribution was legislated by a retrospective 33% tax on 'surplus profits' realised during 2022, defined as taxable profit exceeding 120% of the average taxable profit of the four previous financial years. Companies in scope are those realising at least 75% of their turnover through the production of oil and natural gas, coal mining activities, refining of petroleum or coke oven products.

The Group believes that Kistos NL2 B.V. is out of scope of the regulations as, in its opinion, less than 75% of its turnover under Dutch GAAP (the relevant measure for Dutch taxation purposes) was derived from the production of petroleum or natural gas, coal mining, petroleum refining or coke oven products. Furthermore, the Group understands the implementation of the tax, including its retrospective nature, is subject to legal challenges by other parties and certain EU member states. However, as there is no history or precedent for this tax being audited or collected by the Dutch tax authorities, the Directors, having taken all facts and circumstances into account, applied IFRIC 23, 'Uncertainty over Income Tax Treatments' and made a provision of €47 million ($50.4 million) relating to the Solidarity Contribution Tax within the current tax charge for the prior period. This is the single most likely amount of the charge (excluding any accrued interest) if it becomes payable. The Group expects to get further certainty around this tax position in early 2025.

The Group filed its return in respect of the Solidarity Contribution Tax in May 2024 (which was by the relevant deadline for submission), with its returns stating a nil balance to be paid (for the reasons outlined above). As at the date of approval of these interim financial statements, the Group had not received any correspondence from the Belastingdienst (Dutch Tax Authority) concerning the Solidarity Contribution Tax.

The Group is aware that Solidarity Contribution Tax is subject to legal challenges on the grounds of, inter alia, the legality of its implementation into Dutch law, nature of retrospective application and its specific application to oil and gas producers in the Netherlands. Whilst the Group is not directly involved in these challenges, it will closely monitor developments and any outcome.

Should the Belastingdienst make an adverse ruling against the Group and determine that the Group was grossly negligent or undertook wilful misconduct in submitting a nil return, non-filing or late filing of the tax return (or did not pay an amount indicated in the tax return) then material fines or penalties could apply. Late payment interest would also be incurred from 31 May 2024 until the date of final payment - the current rate of interest applicable being 10%.

6.4 Changes to future tax rates

In March 2024, the UK Government announced an extension of the Energy Profits Levy to 31 March 2029; however, this change was not substantively enacted. On 29 July 2024, the new UK Government announced that the rate of the Energy Profits Levy will increase from 35% to 38% with effect from 1 November 2024. The period that the levy applies is also being extended to 31 March 2030, with the Energy Security Investment Mechanism ('ESIM') remaining in place throughout that period. The government also announced its intention to abolish the levy's main 29% investment allowance for qualifying expenditures incurred on or after 1 November 2024, and also reduce the extent to which capital allowance claims, including first year allowances, can be taken into account when calculating profits subject to EPL. The impact of the proposed changes announced on 29 July 2024 has not been included in the Interim period results as they have not been enacted or substantively enacted at 30 June 2024. It is expected that further details of the proposed changes will be announced on 30 October 2024 with substantive enactment thereafter.

Theses change, if substantively enacted, are not anticipated to have a material impact on the Group's deferred taxation balances although the removal of, and changes to, capital allowances may have a significant adverse impact to the viability of future developments on the GLA.

Section 7 Other disclosures

7.1 Contingent liabilities

7.1.1 Contingent liabilities relating to Tulip Oil acquisition

As part of the acquisition of Tulip Oil in 2021, the following contingent payments could be made to the vendor should certain events occur and/or and milestones be achieved:

· up to a maximum of €75 million relating to Vlieland Oil (now Orion), triggered at FID and payable upon first hydrocarbons based on the net reserves at time of sanction;

· €7.5 million payable upon confirmation by the Group of its intention to retain ownership of the M10a and M11 licences;

· up to a maximum of €75 million relating to M10a and M11, triggered at FID and payable upon first gas, based on US$3/boe of sanctioned reserves; and

· €10 million payable should Kistos take FID on the Q10-Gamma prospect by 2025.

Based on management's current assessments and current status of the projects and developments above, the contingent considerations above remain unrecognised on the balance sheet.

The €7.5 million contingent consideration relating to M10a and M11 was derecognised in full in 2022 as the acquired entity had lost the rights to the relevant licences as at 31 December 2022. The relevant licences were re-awarded in 2023 following a successful appeal, but the Group is advised that the vendor's ability to claim that contingent consideration has lapsed and therefore the amount remains unrecognised on the balance sheet.

7.1.2 Decommissioning-related contingent liabilities

7.1.3 Other contingent liabilities

Contingencies arising from uncertain tax positions are disclosed in note 6.3.

7.2 Subsequent events

7.2.1 Grant of share options

On 1 August 2024, the Company granted a total of 2,303,954 options over its ordinary shares at an exercise price of £1.30 per ordinary share, of which 1,776,923 were granted to Executive Directors. The options vest in three equal annual instalments commencing on the first anniversary of the date of grant, subject to continued employment with no other performance conditions applying.

7.2.2 Balder Future project update

On 21 August 2024, Vår Energi (operator of the Group's interests in Norway), announced that the target production start date for the Balder Future project had been moved to the second quarter of 2025 (previously targeted to be by the end of 2024). The confirmed delay to Balder Future production is a non-adjusting event after the balance sheet date. The impact on incremental capital spend required to accommodate this delay and a revised oil production forecast is subject to review by the operator and Group. Any potential impairment charge recognised in the second half of 2024 will depend on these factors (in addition to the commodity prices prevailing at the time of performing the test). It is also anticipated that the carrying value of the Hybrid Bond will be reduced to zero (on the basis that no amount will become payable) resulting in a gain of c.$9 million to be recognised in the income statement in the second half of 2024.

Appendix A: Glossary

2C - contingent resources

2P - proved plus probable resources

Adjusted Production Costs - production operating costs per the income statement (for Production segments only) less accounting movements in inventory

Average realised sales price - revenue divided by hydrocarbon volumes sold (converted to barrels of oil equivalent using the conversion factors in Appendix C) for the period

bbl - barrel

bcf - billion cubic feet

boe - barrels of oil equivalent

boepd - barrels of oil equivalent produced per day

CGU - Cash-generating unit

CIT - Dutch Corporate Income Tax

Company - Kistos Holdings plc

DSA - Decommissioning Security Agreement

E&P - exploration and production

EBN - Energie Beheer Nederland

EIR - effective interest rate

EPL - Energy Profits Levy

FID - Final Investment Decision

FPSO - floating production storage and offloading vessel

FPU - floating production unit

G&A - general and administrative expenditure

Gas Storage Acquisition - the acquisition of the entire share capital of EDF Energy (Gas Storage) Limited from EDF Energy (Thermal Generation) Limited in April 2024

GLA - Greater Laggan Area

GLA Acquisition - the acquisition, in July 2022, of a 20% working interest in the P911, P1159, P1195, P1453 and P1678 licences, producing gas fields and associated infrastructure alongside various interests in certain other exploration licences, including a 25% interest in the Benriach prospect in licence P2411, from TotalEnergies E&P UK Limited

Group - Kistos Holdings plc and its subsidiaries

kbbl - thousand barrels

kboe - thousand barrels of oil equivalent

kboepd - thousand barrels of oil equivalent produced per day

JV - joint venture

KENAS - Kistos Energy (Norway) AS

LTI - lost time incident

MEG - monoethylene glycol

Mime - Mime Petroleum AS

Mime Acquisition -the acquisition, in May 2023, of the entire share capital of, and voting interests in, Mime Petroleum AS (Mime) from Mime Petroleum S.a.r.l., a company incorporated and operating in Norway

mmboe - million barrels of oil equivalent

MT - metric tonne

MWh - megawatt hour

NCS - Norwegian Continental Shelf

Nm³ - normal cubic metre

norm price - the tax reference price set by the Petroleum Price Council for grades of crude oil sold in Norway

NSTA - North Sea Transition Authority

PDO - Plan for Development and Operation

RNB - Norwegian Revised National Budget

ROU - right of use

scf - standard cubic feet

SGP - Shetland Gas Plant

sm³ - standard cubic metre

SOFR - Secured Overnight Financing Rate

Solidarity Contribution Tax - A tax levied by the Dutch Government, following the adoption of Council Regulation (EU) 1854/2022, which required EU member states to introduce a 'solidarity contribution' for companies active in the oil, gas, coal and refinery sectors. The Dutch implementation of this solidarity contribution has been legislated by a retrospective 33% tax on 'excess profit' realised during 2022, with 'excess profit' defined as that profit exceeding 120% of the average profit of the four previous financial years. Companies in scope are those realising at least 75% of their turnover through the production of oil and natural gas, mining activities, refining of petroleum or coke oven products

SPS - Dutch State Profit Share tax

SURF - Subsea, umbilicals, risers and flowlines

Unit opex - Adjusted Production Costs divided by hydrocarbon production (converted to estimated barrels of oil equivalent using the conversion factors in Appendix C) for the period

Appendix B: Non-IFRS Measures

Management believes that certain non-IFRS measures (also referred to as 'alternative performance measures') are useful metrics as they provide additional useful information on performance and trends. These measures are primarily used by management for internal performance analysis, are not defined in IFRS or other GAAPs and therefore may not be comparable with similarly described or defined measures reported by other companies. They are not intended to be a substitute for, or superior to, IFRS measures. Definitions and reconciliations to the nearest equivalent IFRS measure are presented below.

B1: Pro forma information

Pro forma information shows the impact to certain results of the Group as if the Mime Acquisition had completed on 1 January 2023. Management believe pro forma information in this instance was useful as it allows meaningful comparison of full year results across periods.

No pro forma information is provided in respect of the impact of the Gas Storage Acquisition in 2024 as management consider the pre-acquisition trading result is not representative of future operations because, inter alia, (a) the pre-acquisition trading result in 2024 comprised primarily of the close-out of positions placed by the previous operator in 2023; and (b) the pre-acquisition trading arrangement resulted in a different presentation and accounting treatment of trading gains and losses, which are not comparable to the current activity controlled by management.

$'000	Revenue	Adjusted EBITDA

Six months ended 30 June 2023
As reported	113,805	72,220
Pro forma adjustments for period	15,917	1,666
Pro forma results for six months ended 30 June 2023	129,722	73,886

B2: Net debt

Net debt is a measure that management believe is useful as it provides an indicator of the Group's overall liquidity. It is defined as unrestricted cash and cash equivalents less the face value of outstanding bond debt excluding the Hybrid Bond which, in management's view, represents contingent consideration rather than bond debt due to the payment triggers associated with it.

$'000	Note	30 June 2024	31 December 2023 (restated)
Unrestricted cash and cash equivalents	4.1	69,950	214,789
Face value of bond debt	5.1	(289,893)	(286,596)
Less: Hybrid Bond	5.1	45,000	45,000
Net debt		(174,943)	(26,807)

B3: Adjusted Production Costs and unit opex

Adjusted Production Costs (previously called Adjusted operating costs) are production and operating costs attributable to the Group's three Production segments, adjusted for accounting movements in inventory (being those operating costs capitalised into liquids inventory as produced and expensed to the income statement only when the related product is sold). Unit opex is Adjusted Production Costs divided by barrels of oil equivalent produced for the same period.

The definition of Adjusted Production Costs has changed from the prior period, and now excludes operating costs from the UK Storage segment as such costs are not incurred in the production of hydrocarbons for sale.

$'000	6 months ended 30 June 2024	6 months ended 30 June 2023 (restated)
Production and operating costs per income statement	54,601	35,984
Less: UK Storage segment operating costs	(3,513)	-
Accounting movements in inventory	(5,643)	(5,545)
Adjusted operating costs	45,445	30,439
Pro forma period adjustment	-	11,042
Pro forma adjusted operating costs	45,445	41,481

Total production (kboe)	1,544	1,433
Pro forma period adjustment (kboe)	-	226
Total pro forma production (kboe)	1,544	1,659

Unit opex	$29/boe	$25/boe

Appendix C: Conversion factors

37.3 scf of gas in 1 Nm³ of gas

5,561 scf of gas in 1 boe

149.2 Nm³ of gas in 1 boe

1.7 MWh of gas in 1 boe

34.12 therms of gas in 1 MWh of gas

7 MT of natural gas liquids in 1 boe

28 tonnes of CO₂ equivalent in one tonne of natural gas (CH₄)

Exact conversions of volumes of gas to barrels of oil equivalent (boe), volume of gas to energy (therms or MWh) and volumes of natural gas liquids to boe is dependent on the calorific value of gas and exact composition of natural gas liquids and therefore can change on a daily basis, and may be different to those conversion factors used by other companies

[1] Source: North Sea Transition Authority

[2] Conversion of natural gas (CH₄) to CO2 equivalent is based on the IPCC's AR5 global warming potential factor of 28.

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