RNS Number : 1304O

Kistos Holdings PLC

13 May 2024

13^th May 2024

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Kistos Holdings plc

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

Full-year results for the year ended 31 December 2023

Kistos (LSE: KIST), the low carbon intensity energy production company pursuing opportunities in line with the energy transition, is pleased to provide a summary of its audited full-year results for the year ended 31 December 2023. A copy of the Company's full audited annual report and accounts will be made available shortly on the Company's website at www.kistosplc.com.

2023 Highlights

· On a pro forma basis, Group production averaged 8.8 kboe/d (2022: 10.9 kboe/d), reflecting natural production decline from our UK and Dutch assets, unplanned production interruptions relating to third-party infrastructure in the Netherlands, partially offset by the inclusion of production from the Balder and Ringhorne areas in Norway.

· Adjusted pro forma EBITDA was €122 million (2022: €517 million), reflecting the fall in the gas price from exceptionally high levels in 2022.

· Completed the acquisition of Mime Petroleum AS ("Mime"), adding 24 mmboe of 2P reserves (as of 1 January 2023) and in excess of 2,000 boe/d of production with material future production upside from the Balder Future development (Kistos 10%).

· Year-end 2P reserves of 27.9 mmboe, up from 12.7 mmboe on 31 December 2022 following the completion of the Mime Acquisition.

12 months ended 31 December 2023

		2023 (actual)	2023 (pro forma)¹	2022 (actual)	2022 (pro forma)¹
Average production rate²	boe/d	9,200	8,800	10,600	10,900
Revenue	€'000	206,997	223,092	411,512	568,445
Average realised sales price²	€/boe	71	71	167	158
Unit opex³	€/boe	24	25	10	12
Adjusted EBITDA⁴	€'000	120,777	122,319	380,015	517,202
Statutory profit/(loss) before tax	€'000	(45,858)	n/a	254,125	n/a
Cash	€'000	194,598	194,598	211,980	211,980

1. Pro forma figures for 2023 include Kistos Norway as if it had been acquired on 1 January 2023. The acquisition completed on 23 May 2023. Pro forma figures for 2022 include GLA as if it had been acquired on 1 January 2022. The acquisition completed in July 2022 and is therefore not included in the actual results to 30 June 2022. Minor adjustments have been made to comparative pro forma information following receipt of additional information after completion of the GLA acquisition and to align with the Group's accounting policies and methodology as used in the 2022 Annual Report and Accounts.

2. Average production rate includes gas, oil and natural gas liquids, and is rounded to the nearest 100 barrels of oil equivalent per day. The actual average production rate reflects the number of days during the year businesses were controlled by the Group. Sales and production volumes are converted to estimated barrels of oil equivalent (boe) using the conversion factors in Appendix C to the Financial Statements.

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

4. Non-IFRS measure. Refer to the definition within the glossary and reconciliation in note 2.2.2 and Appendix B1 to the Financial Statements.

Financial

Strong operating cash flow performance and balance sheet with improved flexibility

· Statutory loss after tax of €25 million (2022: €26 million profit after tax) including €59 million of impairment charges, primarily relating to write-offs in the UK Exploration segment.

· Strong operating cash flow generation of €203 million (2022: €291 million) despite weaker commodity price environment

· Cash balances on 31 December 2023 of €195 million (31 December 2021: €212 million) and net debt of €24 million following the assumption of $225 million of bonds issued by Mime, with tax repayment of €80 million to be received in December 2024.

· Retired all the outstanding bonds (€82 million) originally issued by Kistos NL2 as part of the acquisition of Tulip Oil, in December 2023. This will save €15 million on future interest costs and has improved our financial flexibility.

· Capital expenditure on a cash basis was €119 million (2022: €20 million), primarily representing the significant planned ongoing investment in Norway to progress the Balder Future project to production.

Operational

Increasing the Group's reserve base and production profile

· Year-end 2P reserves of 27.9 mmboe, up from 12.7 mmboe on 31 December 2022 following the completion of the Mime acquisition.

· Production from newly acquired Norway assets increased 50% through the year from 312 kboe in H1 2023 to 478 kboe in H2 2023 as new wells came onstream at the Ringhorne platform.

· Estimated Scope 1 CO₂e emissions from our operated activities offshore were less than 0.01 kg/boe in 2023 (excluding necessary flaring during drilling campaigns).

Outlook

Establishing a diversified geographic portfolio with exposure across the energy value chain

· Completion of UK gas storage assets acquisition from EDF in April 2024, diversifying the Company's asset portfolio into a stable marketplace that offers significant growth potential.

· On the Balder Future project in Norway, targeting c.140 mmboe gross (c.14 mmboe net), 11 out of 14 new production wells have been completed, ready for start-up when the Jotun FPSO is installed (scheduled by the operator to be in Q4 2024).

· Net debt on 30 April 2024 of €148 million, following cash consideration paid for UK gas storage assets, ongoing Balder Future Project funding and UK tax payments made in Q1 2024.

· Tax repayment (primarily in respect of capital expenditure incurred during 2023 on Balder Future) of €80 million (excluding accrued interest) due to be received in December 2024.

· Continue to explore value-accretive opportunities in the traditional energy sector, despite challenging fiscal environments, and also in the energy transition space.

Andrew Austin, Executive Chairman of Kistos, commented:

"2023 saw significant changes to the operating environment with commodity prices sharply down on the previous year and an increasingly restrictive fiscal regime in the UK. However, the Group continued to maintain a strong balance sheet, paying down historic debt and generating meaningful cash flow.

Kistos has made significant progress in diversifying its asset base to mitigate against the barriers to further investment in the UK North Sea imposed by the UK Government. The acquisition of UK onshore gas storage assets is a demonstration of the Group's ability to identify opportunities outside of its offshore production portfolio and broaden its sources of revenue.

As a management team fully aligned with shareholders, we remain focussed on seeking value for our investments which complement our existing portfolio and offer value-accretive upside."

Enquiries

Kistos Holdings plc Andrew Austin	via Hawthorn Advisors
Panmure Gordon (NOMAD, Joint Broker) James Sinclair-Ford	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 Holdings plc 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 highly cash generative 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 and a development project. In May 2023, Kistos completed the acquisition of Mime Petroleum A.S. adding 24 MMboe of 2P reserves and significant production. In April 2024, Kistos completed the acquisition of UK gas storage assets, 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 is a low carbon intensity energy producer with Estimated Scope 1 CO₂e emissions from our operated activities offshore Netherlands of less than 0.01 kg/boe in 2023 (excluding necessary flaring during drilling campaigns).

Executive Chairman's Statement

Continued growth

I am delighted to be able to report Kistos' results for the year ended 31 December 2023, with Adjusted EBITDA for the period €122 million on a pro forma basis.

This result was a reduction from the 2022 pro forma Adjusted EBITDA of €517 million, primarily due to the exceptionally high gas prices seen in the prior period. We ended 2023 with total cash of €195 million (2022: €212 million), and Kistos' strong financial position during the year was one of the reasons we were able to acquire Mime Petroleum (subsequently renamed Kistos Energy Norway AS) in May 2023 and assume its bond debt. This resulted in a Group net debt position at the end of the period of €24 million, following the redemption in December of the remaining outstanding bonds that were originally issued on acquisition of Tulip Oil. The redemption of these bonds has resulted in a €15 million saving on future interest costs, as well as improving our financial flexibility by making it easier to manage cash within the Group and permit future external distributions to shareholders.

Production from the Kistos-operated Q10-A field in the Netherlands was impacted by downtime from the scheduled maintenance period, which began in June, and a planned workover campaign that commenced in the fourth quarter of 2022 and concluded in the first quarter of 2023. The results of this campaign were mixed, mainly due to mechanical issues arising from utilising the existing well stock rather than reservoir performance issues. Nevertheless net output from Q10-A reduced significantly from 4,700 boepd in 2022 to 2,700 boepd in 2023 and our team is now focused on minimising future production declines to ensure we extract the maximum value from this asset.

Following its acquisition by Kistos and successful integration into the Group, Norway production increased by more than 50% from 312 kbbl in the first half of 2023 to 478 kbbl in the second half of 2023. This was achieved as Vår Energi, the Balder area operator, brought new wells onstream and production efficiency improved following a summer maintenance turn-around. The average net daily production in Norway for the year was 2,200 boepd, but more than 3,000 boepd in the final quarter.

Meanwhile, the Balder Future development, which is expected to boost our output from the Norwegian Continental Shelf (NCS) to a daily peak during 2025 of 10,000 boepd, continues to make progress. The upgrade of the Jotun floating production storage and offloading vessel (FPSO) is ongoing, with Vår reporting that work on the vessel is, as at April 2024, more than 95% complete. It is focused on executing the remaining construction and commissioning work to enable inshore sail away in time to allow production start-up in the fourth quarter of the year. The project's drilling and subsea facilities activities are progressing according to schedule.

In the Greater Laggan Area (GLA) offshore the UK, despite an unplanned shutdown at the Shetland Gas Plant (SGP) in December, which was caused by an incident in the heating medium system, the GLA fields and infrastructure enjoyed good uptime and produced an average of 4,000 boepd net to Kistos, a decrease from 5,900 boepd in 2022 but in line with the budget. Looking forward, the GLA partners continue to pursue the potential development of the Glendronach field and we expect to benefit from Shell's decision to develop the Victory gas field, which will utilise GLA infrastructure and the SGP, and is due onstream before the end of 2025.

We were disappointed when the Benriach exploration well failed to find hydrocarbons in commercial quantities. However, we were pleased that operations were completed safely and under budget and an extensive data acquisition programme was conducted, which will help inform the geological interpretation of the area. Although we benefitted from enhanced capital allowances in relation to the this well (resulting in the post-tax cost to Kistos being only €4 million) under the Energy Profits Levy (EPL) regime, we continue to see this tax in particular, and fiscal uncertainty in general, as major barriers to investment in the UK North Sea. The recent announcement by the UK Government that EPL is to be extended for another year (to 2029) is at odds with what was supposed to be a temporary 'windfall' tax on exceptional profits, especially as the average 2023 UK gas price was lower than the 2021 average (which was prior to the commencement of the Russia-Ukraine conflict).

Since the end of 2023, we announced and completed the acquisition of EDF's onshore UK gas storage business for cash consideration of £25 million (less closing working capital adjustments). Our entry into this market is another step in our strategy to expand the business through value-accretive acquisitions. However, these facilities also diversify our presence across the energy value chain, giving us a foothold in the midstream market, and align with our objective to own assets with a role to play in the energy transition. We welcome the gas storage team to Kistos and look forward to benefitting from their experience at these sites as we assume operatorship. Their specialist expertise will be highly valuable as we seek to maximise the potential of the assets and evaluate all options to expand and extend operations via other energy storage sources such as compressed air or hydrogen. In essence, Kistos now owns one of the most flexible 'batteries' in the UK, which is vital for the nation's energy security and supply.

Finally, I would like to thank our employees and contractors for their work and commitment to the Company and to thank our suppliers, co-venturers and others for their continued support. It enabled us to build on our platform since the end of 2022 and we will continue to do so in the future. Although we do not set explicit long-term targets for reserves or production, we will maintain our focus on generating substantial returns for investors and I look forward to reporting further progress during the remainder of 2024.

Andrew Austin
Executive Chairman

Chief Executive Officer's Review

Review of Operations

2023 saw Kistos enter Norway with the acquisition of Mime Petroleum, bringing geographical and operational diversification, and significantly increasing the Group's reserves and resources base.

The Netherlands

Q10-A

Q10-A (Kistos 60% and operator) production in 2023 was 2,700 kboepd compared to 4,700 kboepd in 2022. Production was adversely impacted by downtime due to a compressor leak on the TAQA-operated P15-D platform identified following restart of operations after the planned summer maintenance shutdown. This resulted in significantly reduced production rates until the issue was rectified in early September.

Production for the year was also impacted by the mixed results of the well intervention campaign, which concluded during Q1 2023 without achieving the forecasted increase in production rates. We continue to review and integrate the results of these activities into our wider subsurface understanding of the field to evaluate any remaining opportunities, but we now anticipate the 2P reserves recoverable from the field to be lower than originally thought.

The Group is also co-operating 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, which includes potential new developments, is to extend the economic life of the hub for the benefit of all users.

Average realised gas prices fell by 59% to €43/MWh from €105/MWh a year earlier. Combined with a 45% decrease in production rates, this caused total Netherlands revenue in the period to decrease by 76% to €67 million versus €285 million in 2022.

Critically, our Scope 1 emissions intensity remained one of the lowest in the industry, at less than 0.002 kg CO₂e/boe (excluding flaring from drilling operations).

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. This is a proven play in the area and, although this reservoir has low porosity and permeability, it contains natural fractures that can significantly enhance productivity. This was demonstrated in the third quarter of 2021, when Kistos drilled an appraisal well and flow tested an 825-metre horizontal section at a maximum rate of 3,200 boepd.

The Concept Select phase of the development was split into two parts, the first of which completed during Q3 2023. The second phase is nearing completion and, should the decision be taken to progress the project, FID could occur in the second half of 2024, with first oil in early 2026. In the event it goes ahead, this relatively low-cost project is expected to utilise the existing facilities at Q10-A and P15-D. Under currently enacted fiscal regimes, the oil produced would be among the lowest-taxed barrels in the North Sea at a rate of approximately 50%.

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, prior to 28 February 2024, to apply for a permit to drill an appraisal well 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 28 February submission deadline. An update on the status of M10a/M11 will be provided once we receive responses from the relevant authorities.

Other

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 by EBN, which holds the remaining 40%. Initial evaluation of the acreage has now commenced, with previously identified prospects being ranked against our wider portfolio of exploration opportunities.

Onshore, after concluding the safe abandonment of three wells (HRK-1, DKK-3 and DKK-4) at the end of 2022, Kistos commenced the process of land remediation and returning sites to landowners. In 2024, Kistos will continue the remaining abandonment work, focusing on removing the pipeline and filling in remaining cavities.

Norway

Production and drilling activity

Net production from the Balder and Ringhorne fields (Kistos 10%) in the period from acquisition to the end of the year averaged 2,500 boepd, with 22 wells producing oil during the year. Under the joint lifting agreement with Vår, 10 cargoes of crude were lifted from the Balder floating production unit (FPU) in the period post-acquisition, totalling 533 kboe net to Kistos with an average realised price of $81/bbl. For 2024, Kistos has entered into a new sales and lifting arrangement whereby Kistos will sell its share of crude oil only when it has built up sufficient entitlement to fill an offload tanker but will continue to be paid monthly on a produced quantity basis.

Production was positively impacted in the period by the restart in May of the rich-gas riser between the Balder FPU and the Ringhorne platform. This had been temporarily shut in during the first quarter of the year and was permanently replaced in September 2023 during the planned Balder FPU turnaround. Overall production efficiency for Balder and Ringhorne Øst was 87% but improved as the year progressed, reaching 98% in the final quarter.

Other activities in 2023 included: a well intervention campaign to restore output from Ringhorne Øst; the drilling and completion of six new wells with the West Phoenix semi-submersible drilling rig as part of the Balder Future campaign; and the completion of the first of five planned Ringhorne Phase IV wells to be drilled from the Ringhorne platform. The remaining Ringhorne Phase IV wells are anticipated to be completed by early 2025.

We estimate that the full year Scope 1 and Scope 2 emissions intensity from our Norwegian assets was 18 kg CO₂e/boe.

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 Øst fields. The project's target is to extract an additional c.140 mmboe from the area and it will also provide expansion capacity to tie in extra wells to the FPSO after the completion of Balder Future drilling programme.

The upgrade of the Jotun FPSO for the Balder Future development project is ongoing and the refloat of the vessel occurred in late June 2023. This enabled the safe completion of the heavy-lift installation of the turret, turntable and gantry in July. The subsea systems including flowlines, umbilical and risers have now all been installed, with templates, multi-flow bases, flowlines and buoyancy elements for risers also in place. Dewatering of the gas export line and gas lift lines along with flushing of lines and umbilical testing have all been conducted.

In mid-February 2024, the FPSO refurbishment was reported by the operator to be more than 90% complete and only slightly behind the revised plan, with the subsea umbilicals, risers and flowlines (SURF) elements more than 80% complete (all subsea equipment has been delivered and the majority installed, with a summer 2024 campaign scheduled to pre-lay risers ready for the FPSO arrival). Ten out of 14 new production wells have been completed, and all production wells will be ready for start-up as soon as the Jotun FPSO is installed in the field and tie-ins are complete. with the operator's current focus is on executing the remaining construction and commissioning work whilst drilling and subsea facilities activities are progressing according to schedule. The operator's targeted start-up date of the FPSO has been moved to the fourth quarter of 2024, based on an inshore sail away by August 2024.

The United Kingdom

Greater Laggan Area

In July 2022, Kistos marked its entry to the UK Continental Shelf with the completion of the acquisition of a 20% interest in the GLA from TotalEnergies E&P UK Limited. As part of the acquisition terms, a contingent consideration payment of €15.6 million was made in January 2023. This payment was calculated by reference to the average gas price and GLA production during 2022.

The average net production rate from the GLA in 2023 was 4,000 boepd, compared to 6,200 boepd (pro forma) in 2022, reflecting primarily natural reservoir decline. In addition, production during the year was impacted by a period of unplanned outages during March as a result of compressor unavailability, a failure of the monoethylene glycol (MEG) reboiler facilities from August to November, and by an emergency shut-down and 10-day outage following a heating medium pipework failure at the SGP in December. Planned activities, which included approximately three weeks of shut-ins during April to allow for planned pipeline pigging operations, and a three-day planned maintenance window during May were completed according to schedule.

Production from the single well on the Edradour field remains suspended due to facilities constraints relating to MEG management and saw negligible production during 2023. The GLA joint venture continues to monitor the well and its potential restart. So far, other GLA wells have compensated for the production shortfall. Overall GLA output last year was within the original forecast range until the emergency shut down of the SGP in December 2023.

On a pro forma basis, average realised gas prices fell by 53% to 99p/therm in 2023 from 210p/therm a year earlier. This, combined with the reduction in average production rates outlined above, resulted in a decrease in revenue to €99 million from €126 million. Kistos also saw regular liftings of natural gas liquids (C3, C4 and C5+) and the sale of one parcel of crude oil from the GLA during 2023.

A series of three 4D seismic surveys were acquired over the producing GLA fields, with completion occurring ahead of schedule in early July and (due to favourable weather conditions) significantly under budget. The primary aim of the campaign is to evaluate potential infill opportunities over Laggan, Tormore and Glenlivet, and to provide better reservoir monitoring and management of the GLA as a whole. The acquired seismic is currently subject to ongoing processing for 3D and 4D applications, and final results are expected early 2024.

The results of the seismic survey may also help inform JV decisions over the other future developments, including Edradour West. During the year, the JV partners continued to progress options for the Edradour West development, while the Glendronach development previously passed all technical stage gates with the operator and partners. It is now undergoing a recycling of project economics following changes to the cost environment since it was originally assessed. Both of these projects have so far exhibited accretive economics and would utilise the existing GLA subsea infrastructure and the SGP if they are approved for development. The JV is also in the initial stages of evaluating other infill drilling opportunities on the Laggan and Tormore fields.

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 on-stream, will significantly reduce unit operating costs for the GLA partners while providing a life extension for the existing GLA fields.

In 2023, the CO₂ emissions intensity from GLA production (on a Scope 1 and Scope 2 basis) was estimated at 15 kg CO₂e/boe (2022: 12 kg CO₂e/boe), well below the UK average for offshore gas fields of 25 kg per boe^{^[1]}. As production from the GLA naturally declines in 2024, this intensity ratio is anticipated to increase. However, it will be reduced again once Victory comes onstream. The JV partners continue to evaluate and execute energy efficiency and electrification options at the SGP to further reduce the asset's carbon intensity.

Benriach

The Benriach exploration well, located on block 206/05c (Kistos 25%), was spudded on 21 March 2023 by the Transocean Barents drilling rig. A total measured depth of approximately 4,400 metres was reached and an extensive data acquisition programme was conducted, including obtaining rotary sidewall cores, full wireline coverage, live pressures and fluid samples. The campaign confirmed the presence of gas-bearing sands in the target Royal Sovereign formation. However, based on initial analysis, the discovered resource is expected to be sub-commercial and a decision was taken to plug and abandon the well. Drilling concluded ahead of schedule in June 2023, with zero lost time incidents or first aid cases and at a post-tax cost net to Kistos of approximately €4 million. Detailed analysis of the acquired data by the operator is expected to conclude in the first half of 2024 and has the potential to benefit nearby developments (such as Glendronach).

Reserves and resources

Kistos exited 2022 with 2P reserves of 12.7 MMboe. Following the acquisition of the Norwegian interests in May 2023, group 2P reserves at the end of 2023 were 27.9 MMboe.

Pro forma production in 2023 was 3.2 MMboe, while net downwards revisions in the UK and the Netherlands amounted to 4.5 MMboe, arising from revisions to subsurface models and taking into account the reduced performance potential of the single well on the Edradour field.

Our 2C contingent resources are estimated to be 67.5 MMboe at the end of 2023, including the other opportunities in the Balder area in Norway, Orion and M10a/M11 in the Netherlands, and Glendronach and Edradour West in the GLA.

Onshore UK gas storage acquisition

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

Hill Top's working gas capacity is 17.8 million therms, with an ongoing programme to increase this to 21.2 million therms in the short term. At current levels, Hill Top accounts 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. With the potential reactivation of the Hole House facility, which is currently non-operational, it would be possible to increase materially our share of the UK's total onshore gas storage.

Both Hill Top and Hole House have the potential to be repurposed for future energy storage uses, including the storage of compressed air or hydrogen, and concept studies are underway. This would place these assets firmly into the transitional energy space beyond the current key role they play in the UK's supply of gas.

Peter Mann

Chief Executive Officer

Financial Review

		31 December 2023 (actual)	31 December 2023 (pro forma)^{^[2]}	31 December 2022 (actual)	31 December 2022 (pro forma)⁸
Revenue	€'000	206,997	223,092	411,512	568,445
Average realised sales price^{^[3]}	€/boe	71	71	167	158
Unit opex^{^[4]}	€/boe	24	25	10	12
Adjusted EBITDA¹⁰	€'000	120,777	122,319	380,015	517,202
Profit/(loss) before tax	€'000	(45,858)	n/a	254,125	n/a
Earnings/(loss) per share	€	(0.30)	n/a	0.31	n/a
Net cash from operations	€'000	203,159	n/a	290,702	n/a
Net (debt)/cash¹⁰	€'000	(24,319)	(24,319)	130,408	130,408

Production and revenue

Actual production on a working interest basis averaged 9,200 barrels of oil equivalent per day (boepd) in 2023 (2022: 10,600 boepd). This represents a decrease of 14% from a year earlier and reflects the natural decline in production from our UK and Dutch assets, unplanned production interruptions in the Netherlands, partially offset by the inclusion of the Group's interests in Norway from 23 May 2023.

On a pro forma basis (assuming Kistos had completed the acquisitions of the GLA interests and Mime on 1 January 2022 and 1 January 2023 respectively), production was 8,800 boepd (2022: 10,900 boepd). As well as natural decline, this reduction reflects periods of downtime in the Netherlands during the drilling campaign in the first quarter of 2023, unplanned production interruptions following attempted restarts after the planned annual maintenance at the P15-D platform in the summer, and planned annual maintenance and pigging campaigns on the GLA in the UK during April. Again, this was offset by the addition of oil production from the Balder Area in Norway, which saw increases in production rates as the year progressed as new wells came onstream at the Ringhorne platform.

The Group's average realised price across gas and oil sales during the period was €71/boe, and total revenue from gas and oil sales was €207 million, versus €167/boe and €412 million a year earlier. On a pro forma basis, these figures were €71/boe and €223 million, a decrease from €158/boe and €568 million realised in 2022. The 55% reduction in average realisations was a function of the significant reduction in UK and Dutch gas prices in 2023, with realised oil prices improving slightly as the proportion of the Group's revenue derived from the sale of crude increased and we received more frequent payments.

In the Netherlands, the average realised gas price for the year was €43/MWh (2022: €105/MWh, which included the impact of hedges during the first quarter of the year). Based on the average 2023 realised price, cijns (a 'windfall' royalty tax) was not payable for the year. In the UK, the average realised gas price for the period was 99p/therm (2022 pro forma: 210p/therm). The average realised oil price from crude oil sales in Norway on a pro forma basis was $80/boe. This was approximately 3% lower than the average Brent crude price for the period, which was a function of the norm price differential applied by the Norwegian Petroleum Price Council to Balder crude.

Operating costs

Total adjusted operating costs^{^[5]} (which exclude non-cash accounting movements in inventory) were €72 million (2022: €27 million). On a pro forma basis, adjusted operating costs were €82 million (2022: €47 million), with this figure reflecting the inclusion of a full year of production costs in Norway. On a unit opex basis, pro forma costs were €25/boe (2022: €12/boe), reflecting higher production costs in Norway, lower production rates in the UK and Netherlands, and a contracted change from tariff payments to a cost share arrangement for Q10-A at the TAQA-operated P15-D platform.

Adjusted EBITDA

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Pro forma^{^[6]} Adjusted EBITDA	122,319	517,202
Pro forma adjustment	(1,542)	(137,187)
Adjusted EBITDA	120,777	380,015
Depreciation and amortisation	(99,230)	(83,234)
Impairments	(59,023)	(44,547)
Development expenses	(1,146)	(1,752)
Transaction costs	(2,581)	(681)
Share-based payments	(159)	(538)
Contingent consideration movements	3,355	26,993
Operating profit/(loss)	(38,007)	276,256

Adjusted EBITDA was €121 million or €41/boe of production in 2023, compared with €380 million and €139/boe in 2022. This reduction was caused primarily by the significant drop in average gas prices year-on-year, in conjunction with a reduction in overall production rates and higher operating costs arising from lower production and Norway incurring higher unit operating costs than our pre-existing assets. The same dynamic resulted in pro forma EBITDA falling to €122 million or €38/boe of production from €517 million or €130/boe a year earlier. The depreciation charge for the year was €99 million, equivalent to €33/boe produced (2022: €83 million or €30/boe produced).

Impairment charges of €59 million were recognised during the year, primarily relating to the GLA assets, where a sub-commercial result on the Benriach exploration well (Kistos 25%) and decisions by the JV partners to relinquish the Roseisle (14%) and Cardhu (20%) licences has resulted in the acquisition fair values and expenditure post-acquisition being written off. A downwards revision to reserves in the Netherlands combined with a reduction in European gas prices triggered an impairment of €13 million against the Q10-A field.

Capital expenditure

Cash capital expenditure in 2023 was €119 million. Of this, €14 million related to the drilling campaign on Q10-A, which concluded in March 2023. Capital expenditure on the Benriach exploration well, which spudded in March 2023 and completed operations in June 2023, was €20 million net to Kistos. This reduced to €4 million on a post-tax basis after taking into account the investment allowance available under the UK Energy Profits Levy.

In Norway, Kistos' share of cash capital expenditure was €77 million, which was primarily spent on drilling for the Balder Future project, refurbishment costs on the Jotun FPSO and associated subsea facilities. 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 receivable in respect of 2023 Norwegian tax losses (primarily generated by capital expenditure) is anticipated to be approximately €80 million, to be received in December 2024.

Profit/loss before tax

The operating loss for the period was €38 million (2022: operating profit of €276 million). After net finance costs of €8 million (2022: net finance costs of €22 million) principally relating to higher bond interest expense due to the additional debt assumed as part of the Mime Acquisition, which was partially offset by associated foreign exchange gains, a loss before tax of €46 million was recorded (2022: €254 million profit before tax).

Tax

The net accounting tax credit for the period was €21 million, reflecting the deferred tax benefit of the Benriach well impairment, the EPL investment allowance on capital expenditure in the UK and pre-tax losses in Norway arising from the significant capital investment underway on the Balder Future project. The net current tax credit for the year (representing primarily tax due or receivable on profits or losses made in the year) was €23 million (2022: €196 million charge). This is based on the statutory headline rates of 75%, 78% and 50% in the UK, Norway and the Netherlands respectively, offset by capital allowances from our drilling campaign at Benriach, the Balder Future project and the well intervention activity on Q10-A. The prior period included the impact of the Solidarity Contribution Charge tax, a one-off tax levied by the Dutch Government on so-called 'surplus profits' generated in 2022.

Net cash tax receipts for the period were €38 million, comprising €34 million payments in the Netherlands offset by a cash tax refund of €72 million in Norway (2022: €66 million net cash tax payments, wholly relating to the Netherlands).

Balance sheet and liquidity

At the end of 2023, the Group held cash and cash equivalents of €195 million (31 December 2022, €212 million) and net debt of €24 million (31 December 2022, net cash of €130 million). Pre-tax operating cashflow for the year was €165 million (2022: €356 million); the reduction reflecting the decrease in production and realised sales prices offset by a positive working capital movement arising from settlement of gas sales made in December 2022 when prices were significantly higher than 2023's averages.

As part of Kistos' acquisition of Mime Petroleum in May 2023, the latter's outstanding bond debt was restructured. This resulted in Kistos assuming $270 million of debt, including $45 million of Hybrid Bonds. These only become payable in whole or part if 500 kbbl is offloaded and sold from the Jotun FPSO by certain dates. In the event this has not been achieved by 31 May 2025, then no payment will be due under the terms of the hybrid bonds.

The remaining $225 million bond debt is split between a $120 million bond and a $105 million bond. 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. At 31 December 2023, the face value of the bonds had increased to $242 million following the issuance of payment in kind bonds.

During the year, the Group made market purchases of certain amounts of bond debt issued by its Dutch subsidiary in 2021 as part of the Tulip Acquisition. Then, in December 2023, it utilised surplus cash on its balance sheet to exercise a call option to redeem in full the remainder of the bonds. The total cash cost of bond repurchases in 2023 was €84 million (excluding accrued interest) and resulted in a net saving of €15 million in scheduled interest payments to original maturity.

The current tax liability at the end of 2023 was €129 million (2022: €143 million). Both periods include €47 million provided for in respect of the Solidarity Contribution Tax, for which the Group believes there is a strong argument that the relevant Dutch subsidiary, Kistos NL2 BV, is out of scope (see note 6.4 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. Nonetheless, the settlement of the remaining €82 million of other current tax liabilities will have a material impact on operating cash flow in 2024.

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 in December 2023, Kistos expects to receive over 900 million NOK (€80 million), not including accrued interest, in December 2024.

Going concern

To assess the Group's ability to continue as a going concern, base case and downside cash flow forecasts have been prepared which cover a period of at least twelve months from the approval of this Report.

The forecasts and projections made in adopting the going concern basis take into account forecasts of commodity prices, production rates, operating and G&A expenditure, committed and sanctioned capital expenditure, foreign exchange rates and the timing and quantum of future tax payments and receipts.

Based on the judgments summarised below, and provided in detail within note 1.2 to the Financial Statements (which includes consideration of both reasonably plausible downside scenarios, and mitigating actions management could take) these Financial Statements have been prepared on a going concern basis.

The Group's cash balances as at the end of April 2024 was €80 million. To assess the Group's ability to continue as a going concern, cash flow forecasts were evaluated for the period to June 2025 (the going concern period), by preparing a base case forecast and various downside sensitivity scenarios.

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

However, due to the potential for one or more of the reasonably plausible downside scenarios occurring, and due to their being no guarantee that the Group would be successful in achieving mitigating actions to remedy the adverse impact thereof, a material uncertainty exists which may cast significant doubt about the Group's continued ability to operate as a going concern and its ability to realise its assets and discharge its liabilities in the normal course of business. Nonetheless, this Annual Report and Financial Statements have been prepared on the going concern basis and do not include any adjustments that may result from the outcome of these uncertainties. Further information concerning the key assumptions and judgements made in the assessment of going concern is disclosed in note 1.2 to the Financial Statements.

Our ESG Goals

In late 2023, we began re-evaluating our ESG goals to explore whether any adjustments or refinements were needed. We have now developed a revised set of ESG goals for 2024.

We concluded that some of our previously published goals were no longer aligned with our evolving business while others were not applicable at a Group level. We have therefore developed, approved and published a revised set of ESG goals, which will apply from 2024.

We believe the following ESG goals more accurately align with our current business strategy and will allow both Kistos and our stakeholders to measure progress across our strategic operations more effectively.

Caring for the environment

Achieve carbon neutrality for Scope 1 and 2 emissions by 2030.

Maintain zero operational spills annually in our operated sites^{^[7]}.

Maintain zero hazardous contaminants in discharges to water annually in our operated sites⁷.

Incorporate nature-inclusive design principles into new operated projects⁷.

Putting people first

Achieve zero harm to workers annually in our offices and operated sites⁷.

Recruit from a diverse, qualified group of candidates to increase range of thinking and perspective.

Foster a culture that encourages collaboration, flexibility and fairness to enable all employees to contribute to their potential and increase retention.

Embed diversity and inclusion in policies and practices, and equip leaders with the ability to manage diversity and be accountable for the results.

Our ESG Performance

We manage the ESG issues associated with our Group through responsible and sustainable business practices.

Environment

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 also included as part of ongoing operational and project decisions.

Our recently announced 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 have 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. The assets also have the potential to be repurposed for future energy storage, including the storage of compressed air or hydrogen. 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.

Direct emissions and air quality

In 2023, our operations included drilling infill wells offshore the Netherlands at the start of the year. And in the UK, we worked with operator TotalEnergies to drill the Benriach exploration well west of Shetland in the second quarter. Drilling work in Norway was ongoing, with six wells drilled and completed as part of the Balder Future campaign, and a further five Ringhorne Phase IV wells drilled from the Ringhorne drilling platform.

One of our new ESG goals is to achieve carbon neutrality for Scope 1 and Scope 2 emissions by 2030. 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. Due to declining production levels from the Q10-A wells in 2023 compared to 2022, our Scope 1 emissions intensity increased year-on-year. However, we saw a reduction in the absolute level of Scope 1 emissions due to the increased capacity for generating renewable energy on the platform - see case study.

Our Scope 2 emissions primarily relate to the combustion of gas in compressors on the P15-D platform for processing and exporting the gas produced from Q10-A.

Actual emissions from operated assets

kg CO₂e/boe		2023	2022
Scope 1	Excluding flaring	<0.01	<0.01
Scope 1	Including flaring	0.37	0.28
Scope 1 and Scope 2	Excluding flaring	18.5	13.8
Scope 1 and Scope 2	Including flaring	18.9	14.1

Tonnes CO₂e		2023	2022
Scope 1	Excluding flaring	3	5
Scope 1	Including flaring	643	855
Scope 1 and Scope 2	Excluding flaring	32,261	42,393
Scope 1 and Scope 2	Including flaring	32,901	43,243

We don't flare as part of our routine production operations, and only permit it when starting up or closing down to depressurise systems, and from operated rigs during drilling and well-intervention campaigns. Even then, we have improved these processes to make them more carbon efficient. We have also implemented a programme to identify and prevent methane leaks from our operations with annual inspections, exceeding the four-year inspection requirement.

Across the Q10-A platform in the Netherlands, as well as our non-operated interests in the Greater Laggan Area (GLA) offshore the UK and on the Norwegian Continental Shelf (NCS), the Group's Scope 1 and Scope 2 emissions are significantly 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^{^[8]}.

Operational energy use

The Q10-A platform is unmanned and is powered using renewable energy generated by solar panels and wind turbines. Compared to using diesel generators, Kistos estimates this saved approximately 21 tonnes of CO2 emissions per year. Similarly, we estimate that our policy of conducting offshore visits via boat rather than helicopter saved more than 15 tonnes of CO2 emissions in 2023.

In Norway, the Balder FPU is relatively old and uses about 100,000 tonnes of diesel per year. As part of the Balder Future project, this vessel will be retired from the field by 2030 at the latest, with the newer and more efficient Jotun FPSO moving onto station and eventually taking over the processing and storage of all production from the Balder field. We are also working closely with Vår Energi on electrification-from-shore options for the wider Balder/Grane area.

Spills and incidents

Recognising that spills and incidents is one of our main material issues, we have set ourselves a goal to maintain zero operational spills annually in our operated sites.

We have robust processes in place to prevent major accidents and avoid spillages at sea, as well as clearly defined mitigation and clean-up procedures should an unexpected incident occur. For our operated assets, we are obliged to have an emergency response team available around the clock and we take part in emergency response exercises run by the operator for our other assets.

During 2023, we experienced no spills or loss of containment within our operated assets. In December 2023, we experienced an unplanned shutdown of operations at the Shetland Gas Plant (SGP) following a failure of the heating medium system. This resulted in a release of steam, with no harm to personnel. We worked closely with the operator TotalEnergies during and after the incident to understand the root causes of the failure while also acknowledging the strong performance by the operator on its incident management and communication.

Effluents and waste

In line with the strict regulations governing our sector, one of our revised ESG goals is to maintain zero hazardous contaminants in discharges to water annually in our operated sites.

We strictly adhere to guidelines, compliant with EU REACH regulations, that prevent the use of certain chemicals and materials that are considered harmful to the environment.

Biodiversity

In working towards our stated ESG goal to incorporate nature-inclusive design principles into new operated projects, we aim to use building materials and construction methods that promote local habitats where feasible.

Furthermore, we employ people to watch bird migrations and inform us when flaring can be conducted safely without affecting birds and other local wildlife. We also limit the ultrasonic sounds from our operations to prevent harm to marine life and take specialist advice to keep seals away from our offshore platforms.

Social

Health and safety

Reflecting its importance as one of our most material issues, we have revised our relevant ESG goal for health and safety. We now define our aim as being to achieve zero harm to workers annually in our offices and operated sites.

Having incorporated third-party contractors into our safety culture, our HSE performance remains strong. In pursuit of our zero-harm goal, we had zero lost time incidents (LTI), zero incidents of non-compliance, one near miss and zero identified (non-reportable) hazards during the three months of drilling and testing operations in 2023.

We already have strict protocols and rigorous testing procedures in place to keep our employees and contractors safe, but we continue to make improvements where we can.

· In 2023, we established a Process Safety Management Standard. This comprises 15 requirements for managing the main risks across our operated and non-operated assets. This standard covers activities for safeguarding the integrity of wells, pipelines and facilities associated with Major Accident Hazards (MAHs). The requirements are grouped under four categories: risk management; design and construction; operations, inspection and maintenance; and process safety culture.

· We also replaced our 12 safety rules with the International Association of Oil & Gas Producers' (IOGP) nine Life-Saving Rules in 2023. By adopting these industry-wide actions - which cover topics such as driving, confined spaces, energy isolation and working at height - we have simplified, expanded and added to the controls we use to keep everyone safe while at work. These Life-Saving Rules are combined with our 13 Start-Work Checks, which help workers verify that the necessary controls and safeguards are in place before starting a task.

Looking ahead to 2025, when our Dutch subsidiaries will need to report in line with the new Corporate Sustainability Reporting Directive (CSRD), we are already aligning our businesses in the UK, the Netherlands and Norway under a five-year HSE plan. As well as having annual plans for asset integrity and process safety, we now have a timeline for improving HSE leadership, certification, contractor management, and behavioural safety programmes that runs to 2028.

Workplace culture

Our revised ESG goals now include our ambition to foster a culture that encourages collaboration, flexibility, and fairness to enable all employees to contribute to their potential and increase retention.

We have retained a flexible working environment for all employees. However, we remain mindful of the need for direct interactions and networking to support the professional development of our people.

We encourage employees to seek out relevant training courses that will further their professional development and provide benefits to the Group. We will cover the cost of such courses and grant employees time off to attend courses that are relevant or appropriate to the role.

Diversity, equality, and inclusion

The importance we place on diversity, equality, and inclusion (DEI) is reflected in two of our ESG goals. As well as recruiting from a wide range of candidates to increase diversity of thinking and perspective, we also intend to identify and break down systemic barriers to full inclusion by embedding diversity and inclusion in policies and practices and equipping leaders with the ability to manage diversity and be accountable for the results. When hiring, we do not discriminate on grounds of disability, ethnicity or gender; and offer the same access to training to all employees regardless of background or situation.

As we have a relatively small number of employees across the organisation, each role is unique within its region. It is therefore not meaningful to measure the pay gap across genders. When seeking to fill new roles, we offer remuneration packages commensurate with level, experience and technical expertise required, and do not consider the gender of the applicant.

Human rights

Kistos recognises its responsibility to respecting human rights in all aspects of doing business and we have embedded human rights in our Code of Business Conduct and in our Modern Slavery Statement. We believe that an integrated approach to human rights, embedded into our policies, business systems and processes, allows us to efficiently and effectively manage human rights within our existing ways of working. Our approach applies to all our employees and contractors. We focus on four areas where respect for human rights is particularly critical to the way we operate: labour rights, communities, supply chains, and security. We have community feedback mechanisms at all our major facilities. These mechanisms enable employees, people in the communities where we operate, contractors and any third party to raise concerns, so they can be resolved, enabling us to meet our commitment to provide access to remedy.

Principal Risks and Risk Management

Kistos identifies, assesses and manages the risks critical to its success.

The Group's business, people and reputation are safeguarded by overseeing these risks. We use the risk management process to ensure that we are aware, and in control, of the risks we face. This way, we can achieve our strategic goals and create value. We may choose to accept, manage, transfer or remove the risk depending on its nature. We may manage the risk with controls or other actions that reduce its impact. We may transfer the risk to others who can handle it better. Or we may remove the risk by stopping the activities that cause it.

Management maintains a Corporate Risk register based on risks identified at asset and business level, which includes the underlying risks and mitigating actions for each. This is reviewed by senior management, the executive directors, the Audit Committee, and the Board.

The principal risks facing the Group, and the actions taken to minimise their likelihood and/or mitigate their impact, are listed in the following table. The Directors confirm they have conducted a thorough assessment of the main risks that affect the Group, including those that would significantly harm its strategy, business model, future performance or liquidity.

(A) Political Changes in national government policies towards oil and gas-focused companies could adversely impact the ability of the Group to deliver its strategy.
Change in risk level: Increase		Owner: Peter Mann (CEO)
Potential impact	Mitigation		Risk movement
· Refusal of permitting applications for development, appraisal and exploratory drilling. · Increased costs relating to permitting and legal matters, and delay to projects. · Impairment of intangible assets. · Inability to win new licences. · Loss of value to stakeholders.	· Active member of Element NL, OEUK, BRINDEX, Offshore Norge and other industry associations. · Engagement with the respective governments and other appropriate organisations to ensure the Group is kept abreast of expected political changes. · Active role taken in making appropriate representations to the relevant departments in governments.		This risk has increased in 2023: · Changes in the Dutch political landscape occurred in 2023. · A General Election is anticipated in the UK later in 2024, which may result in a change in government.

(B) Growth of business and reserves base The Group's growth strategy is primarily dependent on identifying new reserves and resources, and is delivered through development and acquisition. Organic growth is focused on developing existing resources into producible reserves. A focus on growth of the business and the reserves base outside of existing assets to increase immediate perceived shareholder value may give rise to missed opportunities and reduced capital allocation to the existing portfolio. As part of this growth strategy, there is a risk that the Group may fail to identify attractive acquisition opportunities, acquire businesses without performing appropriate due diligence or select inappropriate exploration work programmes. Exploration drilling may deliver adverse results due to factors including poor quality (or misinterpretation of) data, failure/underperformance of offshore vessels or other crucial equipment, unforeseen problems occurring during drilling and delays to offshore operations due to unfavourable weather. Long-term commodity price forecasts and other assumptions used when assessing potential projects and investment opportunities can have a significant influence on the forecast return on investment. Any expansion into new markets, such as onshore gas storage, may give rise to lower than expected returns due to unfamiliarity with the relevant activities and higher than anticipated integration costs.
Change in risk level: Increase		Owner: Andrew Austin (Executive Chairman)
Potential impact	Mitigation		Risk movement
· Reduced asset value, leading to potential impairment of oil and gas assets, and/or intangible exploration and evaluation assets. · Actual or perceived overpayment for acquisitions, leading to impairments of goodwill and assets. · Adverse reputational and share price impact.	· A broad range of acquisitions and similar opportunities are evaluated internally, with support from subject matter experts where appropriate. Such targets are scrutinised by the Board, including the Non-Executive Directors, who challenge the Executive team and other senior management. · Strong relationships are maintained within the industry. · A rigorous assessment process evaluates and determines the risks associated with all potential business acquisitions and strategic alliances, including conducting stress-test scenarios for sensitivity analysis. If applicable, each assessment includes an analysis of the Group's ability to operate in a new jurisdiction. · Country managers and senior team members with responsibility for activities attend weekly senior management meetings, where concerns can be raised and the status of current business development projects is updated. · Exploration, appraisal and development cases are robustly assessed and stress tested against cost, price and taxation sensitivities.		This risk has increased in 2023: · The Group maintains its strategy of securing additional reserves. · The upstream M&A environment, whilst still remaining active on a global scale, has seen fewer attractive opportunities arising in the UK and Netherlands.

(C) Climate change and energy transition Changes in laws, regulations, policies, obligations and social attitudes relating to the transition to a lower carbon economy could lead to higher costs, or reduced demand and prices for oil and gas, impacting the profitability of the Group. Sources of debt and equity finance may become more expensive or restricted as investors diversify away from oil and gas-based investments. Climate change may result in an increase in the frequency of severe adverse weather conditions.
Change in risk level: No change		Owner: Peter Mann (CEO)
Potential impact	Mitigation		Risk movement
· Increased difficulty in accessing finance due to reduced appetite for investing in the oil and gas industry. · Increased difficulty in obtaining regulatory approval for new or increased offshore production activities. · Stranded assets. · Adverse impact on operating cash flow due to higher carbon credit costs. · Disruption to operations from extreme weather events may result in shut-ins, physical damage to assets, lost production and reduced cash flow.	· Active reviews of the Group's strategy towards energy transition, with an aim to provide long‑term returns to shareholders, and consideration of the impact of climate change and potential changes to policy in decision making. · Environmental considerations are a key factor in determining any potential inorganic growth activity. · Value of projects is discounted in the future for later life production to take into account possible reduced demand for hydrocarbons. · Stress tests of budgets and forecasts in respect to the cost of carbon emission allowances. · Continue to investigate and implement actions that could reduce the Group's environmental footprint, where it makes commercial and financial sense to do so. · Design and operate assets to work in the majority of weather conditions and undertake lessons learnt when storms and other events disrupt production. · Working closely with operators and partners to understand and manage planning, production forecasting.		No change in 2023: · Although climate change and energy transition remain a key focus for the Group, limited adverse impact has been experienced with regards to the availability of financing opportunities and wider hydrocarbon demand. This is expected to remain in the short- to medium-term.

(D) Cyber security There is a risk of financial loss, reputational damage and general disruption from a failure of the Group's IT systems or an attack for the purposes of espionage, extortion, terrorism or to cause embarrassment. Any failure of, or attack against, the Group's IT systems may be difficult to prevent or detect, and the Group's internal policies to mitigate these risks may be inadequate or ineffective. The Group may not be able to recover any losses that arise from a failure or attack. As the Group grows, there are more IT areas to standardise and migrate up to Group standards. In interim periods, there is an increased risk of incidents until such time as policies and standards are fully aligned.
Change in risk level: Increase		Owner: Richard Slape (CFO)
Potential impact	Mitigation		Risk movement
· Financial loss from phishing attacks that may not be recovered. · Reputational impact from leak of market-sensitive data or personal information. · Fines and financial penalties may be levied in the event of a data breach.	· Outsourcing of the provision of IT equipment and help-desk services to competent and experienced third parties. · Robust network management systems in place to protect the Group's IT environment. · Well-designed IT security management model with defensive structural controls. · Set of rules and procedures in place, including a Disaster Recovery Plan, to restore critical IT functions. · Regular mandatory staff training and awareness of cyber security matters such as phishing attacks. · Following any acquisition, plans in place to move acquired businesses onto common IT platforms as soon as possible, using its IT contractor to undertake assessments, gap analyses and on-site audits. · A detailed understanding of IT environment on any potential acquisition target is typically obtained during due diligence to assess level of current risk (if unacceptable, transactions may not go ahead).		This risk has increased in 2023: · Higher level of attempted cyber security incidents experienced to date. · Business acquisitions give rise to diverse IT systems, bringing additional risk before, during and after integration.

(E) Joint venture activity As a minority non-operating partner in the GLA and Balder partnerships, operated by TotalEnergies and Vår Energi respectively, the interests and objectives of the partners may not be aligned.
Change in risk level: Increase		Owner: Peter Mann (CEO)
Potential impact	Mitigation		Risk movement
· Longer decision-making processes resulting in loss of asset value. · Impairment of oil and gas assets, and exploration and evaluation assets. · Reduction in reserves and resources. · Capital diverted into projects and developments not aligned with Group strategy. · Inability to meet joint venture cash calls, which may ultimately mean breach of joint operating agreements (JOAs) and loss of licence.	· Representation and active participation in all of the joint ventures' committees (including operating, finance and technical). · Regular engagement with the joint venture operator and other participants with regards to key decision making, preparation and approval of work programmes and budgets, and general strategic direction.		This risk has increased in 2023: · The Mime acquisition has resulted in the Group being a minority partner in another joint venture. · However, with a non-blocking vote in its non-operated interests, the Group is always at risk of being voted into decisions with which it does not agree.

(F) HSE and compliance The Group is exposed to various risks in relation to HSE, compliance, planning, environmental, regulatory, licensing and other permitting rules associated primarily with production operations, drilling and construction. There is a risk that the Group and/or its primary contractors are in breach of their regulatory obligations with one of the principal regulators in connection with the Group's activities, whether operational (for example, maintaining offshore production consents or a loss of hydrocarbon containment) or corporate (for example, adhering to listing rules and market disclosure regulations). This could restrict the Group and/or its primary contractors' capacity to obtain permits or carry out the Group's activities.
Change in risk level: Increase		Owner: Peter Mann (CEO)
Potential impact	Mitigation		Risk movement
· Injuries to workforce. · Harm to the environment. · Physical damage to assets and infrastructure. · Financial or other penalties imposed. · Reputational damage. · Loss of licence to operate.	· Working closely with regulators to ensure that all required planning consents and permits for operations are in place. Maintenance of continual dialogue with all stakeholders to understand emerging requirements. · Conducting activities in accordance with Board-approved policies, standards and procedures. · Code of Business Conduct and compliance programmes in place to provide assurance on conformity with relevant legal and ethical requirements. · Emergency response plans in place and exercises undertaken to prepare for incidents. · External consultants with experience in managing risk developments employed to help complement the existing team skills. · Audit and Disclosure Committees.		This risk has increased in 2023: · The Group is now operating in a new jurisdiction following the Mime acquisition. · Increased level of offshore operations and regular oil tanker liftings have a greater potential for HSE incidents. · Greater focus from regulatory bodies on compliance matters in current environment.

(G) Hydrocarbon production and operational performance The Group's production volumes (and therefore revenue) are dependent on the operational performance of its producing assets. The Group's producing assets are subject to operational risks, including, but not limited to, compressor failures, lack of sufficient critical chemical stocks and spare parts, failure of electrical power supply lines, pipeline corrosion, asset integrity and health, safety, security and environment incidents; and low reserves recovery from the field and exposure to natural hazards such as extreme weather events.
Change in risk level: Decrease		Owner: Peter Mann (CEO)
Potential impact	Mitigation		Risk movement
· Reduced cash flow from operations. · Increased cash costs per barrel equivalent. · Earlier cessation of production if operational performance issues cannot be rectified economically. · Impairment of assets and loss of stakeholder value.	· Continuous review of production performance from each asset, facilitating performance planning well intervention activities as needed. · To the extent possible, discussions held with third parties to manage shutdowns both planned and unplanned. · Planned and unplanned downtime assumptions built into the corporate budgeting cycle and cash flow projections.		This risk has decreased in 2023: · Following the acquisition of interests in Norway, the Group's production base is further diversified and thus is no longer exposed to single points of failure.

(H) Project delivery There is a risk of delays in project delivery and higher costs being incurred, especially under the current high inflationary environment. Continued delays to the Balder Future project risk material cost increases and potential additional delay to first oil.
Change in risk level: Increase		Owner: Peter Mann (CEO)
Potential impact	Mitigation		Risk movement
· Delayed and/or reduced cash flow from operations, leading to an inability to adequately finance other future developments. · Impairment of assets. · Reduction in reserves and resources.	· Projects have a clear project delivery framework with a responsible project lead. · Delivery against project objectives, timeline and cost are regularly monitored. · Project costs are stress tested against cost increases with adequate contingency built in to estimates. · Cash flow risk on the Balder project is partially mitigated via the Hybrid Bond structure, whereby the Hybrid Bond will be released in full if Balder Future first oil is delayed beyond May 2025.		This risk has increased in 2023: · Operator progress on the Balder Future project, and in particular upgrade of the Jotun FPSO, has consistently fallen behind schedule and over budget, giving rise to a risk of further delay to the projected first oil date.

(I) Retention of key personnel The Group may not be able to retain key personnel, and there can be no assurance that it will be able to continue to attract and retain all personnel suitably qualified and competent necessary for the safe and efficient operation and development of its business. Share options previously granted may be out of the money, reducing incentives for staff to remain with the Group.
Change in risk level: Increase		Owner: Peter Mann (CEO)
Potential impact	Mitigation		Risk movement
· Delay to, or cancellation of, projects as a result of lack of appropriately qualified employees to undertake activities. · Loss of 'corporate knowledge' through lack of staff retention, leading to inefficiencies, delays and increased cost.	· The Board seeks to cultivate a safe, respectful working environment where people can thrive. · Benchmarking exercise undertaken by management on reward packages to ensure that acquired staff are retained through a strong remuneration culture. · Workplace surveys undertaken to ascertain morale and employee concerns and allow management to swiftly address any issues. · Long-term share incentive plans in place are regularly reviewed by the Remuneration Committee.		This risk has increased in 2023: · Current share prices means employee share options granted in 2022 and 2023 are now out of the money. · Increased competition for qualified staff seen in adjacent green industries, such as CCUS.

(J) Commodity price The Group's cash flow and results are heavily dependent on natural gas and other commodity prices. These, in turn, are dependent on several factors including the impact of climate change concerns, geopolitics (including events such as the Russia-Ukraine and Israel-Palestine conflicts and other unrest in the Middle East impacting shipping activities) and regulatory developments.
Change in risk level: No change		Owner: Richard Slape (CFO)
Potential impact	Mitigation		Risk movement
· Adverse impact on operating cash flow. · Impairment of oil and gas assets. · Inability to meet bond covenants or repay debt. · Restricted access to financing opportunities in case of a sustained low-price environment.	· Oil and gas markets continuously reviewed by the Board to determine whether future hedges are needed. · Necessary contracts in place to undertake hedging activities if required. · Cash flow projections, liquidity analyses and economic models regularly tested for downside price scenarios. · Exercises undertaken to identify cost reduction and rationalisation opportunities to optimise operating cost per barrel (while maintaining safe and compliant operations).		No change to this risk in 2023: · Gas prices are lower compared to prior year but still higher than historic norms. · Market no more or less volatile compared to prior year. · Volatility provides increased opportunity to generate profits from gas storage trading activity.

(K) Liquidity Adverse changes to production, commodity prices, taxation and surety bond requirements may put pressure on the Group's available liquidity, constraining its options to grow the business or meet obligations to joint venture partners, suppliers and tax authorities. In extreme downside cases, liquidity pressures may result in minimum liquidity covenants being breached and risk of insolvency.
Change in risk level: Increase		Owner: Richard Slape (CFO)
Potential impact	Mitigation		Risk movement
· Inability to pay suppliers, contractors and employees as liabilities fall due, leading to reputational damage and withdrawal of services. · Non-payment of taxes as they fall due may result in investigations or stringent penalties charged. · Inability to meet bond covenants or repay debt leading to restructuring, shareholder dilution or insolvency.	· Regular review of the Group's cash forecasts and its covenants to ensure an adequate headroom of cash availability. · Engagement and strong relationships with the bond market, surety bond providers and other potential providers of finance to manage access to liquidity if required.		This risk has increased in 2023: · Bond debt issued by Kistos NL2 has been fully redeemed, removing those bond covenants and reducing future interest cash outflows. · Redeeming Kistos NL2's bonds has materially reduced the overall cash position. · Material additional debt has been taken on as part of the Mime acquisition, and there is a reduced level of cash headroom overall.

(L) Decommissioning costs and timing The future costs and timing of decommissioning is a significant estimate; any adverse movement in price, operational issues, or reductions in reserves and resource estimates could have a significant impact on the cost and timing of decommissioning. Where decommissioning costs are to be shared as part of a joint venture, the Group is exposed to the risk of partners not fulfilling their commitments. Changes to commodity prices, the taxation regime, inflation rates and other factors may mean that the Group is not able to renew its surety bonds in respect of its DSA obligations, resulting in the Group having to cover its obligations fully in cash and restricting the amount of funds available for other opportunities and day-to-day operations. Significant adverse changes to cash flows may result in insufficient resources to meet its decommissioning obligations, exposing the Group to sanction from regulators.
Change in risk level: No change		Owner: Richard Slape (CFO)
Potential impact	Mitigation		Risk movement
· Reduction in cash flows available for other projects if decommissioning costs materially exceed estimates. · Adverse reputational, regulatory and legal impact if decommissioning obligations cannot be fulfilled.	· In-house decommissioning experience, coupled with focus on delivering asset value to defer abandonment liabilities. · Decommissioning security arrangements and postings in place for UK assets, which mitigate risk from a regulatory and joint-venture partner perspective. · Strong relationships with surety bond providers and confidence that the surety market can continue to provide security for the expected DSA provisions.		No change to this risk in 2023: · Underlying nature of decommissioning risks remain unchanged.

(M) Taxation Longer-term additional and increased taxes imposed on oil and gas companies by governments, in reaction to so-called 'windfall profits' arising from short-term movements in commodity prices, have led to a higher tax burden. Uncertainty over tax regimes may also hinder future investment decisions and reduce the returns from, and profitability of, operations. Should the Dutch tax office rule unfavourably against the Group with regards to the Solidarity Contribution Tax, this would have a material impact to the Group's liquidity.
Change in risk level: No change		Owner: Richard Slape (CFO)
Potential impact	Mitigation		Risk movement
· Material adverse impact to liquidity position if adverse finding received with regards to Solidarity Contribution Tax. · Retrospective taxation or material changes to tax regimes may render currently economic projects unviable, forcing earlier cessation of production (and reducing overall government tax take), giving rise to asset impairment risk. · An increase in jurisdictions with higher tax rates and unpredictable tax regimes may reduce the hopper of available acquisition and expansion opportunities.	· Engagement with various industry bodies to raise concerns and suggest alternative approaches to proposed taxation policies. · Projects and liquidity projections modelled with various tax sensitivities in place. · Support and advice of external experts and legal counsel on taxation matters, including the Solidarity Contribution Tax, is regularly obtained for areas where significant uncertainty and judgement exists. · Our investment strategy is continuously reviewed, and decisions may be taken to not invest further in, or to withdraw from, jurisdictions with a recent history of significant adverse tax changes, implementation of retrospective taxation, or where the taxation regime proves too burdensome.		No change to this risk in 2023: · Taxation regimes have, on the whole, been more stable than in 2022, when governments hastily introduced adverse tax changes in response to higher commodity prices. · Risk remains that tax take remains elevated, even in a lower commodity price environment.

Consolidated Financial Statements

Consolidated income statement

€'000	Note	Year ended 31 December 2023	Year ended 31 December 2022
Revenue	2.1	206,997	411,512
Other operating (expense) income		(188)	11
Exploration expenses		(2,194)	(374)
Production costs		(72,888)	(22,927)
Development expenses		(1,146)	(1,752)
Abandonment expenses		(1,693)	-
General and administrative expenses	3.2	(11,997)	(9,426)
Depreciation and amortisation	2.4, 2.5	(99,230)	(83,234)
Impairment	2.6	(59,023)	(44,547)
Change in fair value and releases of contingent consideration	2.8.2	3,355	26,993
Operating (loss)/profit		(38,007)	276,256
Interest income	3.5	9,296	267
Interest expenses	3.5	(28,771)	(11,283)
Other net finance income/(costs)	3.5	11,624	(11,115)
Net finance costs		(7,851)	(22,131)
(Loss)/profit before tax		(45,858)	254,125
Tax credit/(charge)	6.1	21,177	(181,229)
Solidarity Contribution Tax charge	6.4	-	(46,935)
Total tax credit/(charge)	6.1	21,177	(228,164)
(Loss)/profit for the period		(24,681)	25,961

Basic earnings per share (€)	3.1	(0.30)	0.31
Diluted earnings per share (€)	3.1	(0.30)	0.31

Consolidated statement of other comprehensive income

€'000	Note	Year ended 31 December 2023	Year ended 31 December 2022
(Loss)/profit for the period		(24,681)	25,961
Items that may be reclassified to profit or loss:
Losses on cash flow hedges	5.6	-	(9,404)
Hedging losses reclassified to profit or loss	5.6	--	21,185
Income tax on items of other comprehensive income	5.6	-	(5,891)
Foreign currency translation differences	5.6	93	(43)
Total other comprehensive income		(24,588)	31,808

Consolidated balance sheet

€'000	Note	31 December 2023	31 December 2022
Non-current assets
Goodwill	2.5	49,154	10,913
Intangible assets	2.5	31,315	43,338
Property, plant and equipment	2.4	411,901	282,474
Deferred tax assets	6.2.2	1,932	566
Investment in associates		62	61
Other long-term receivables		149	102
		494,513	337,454
Current assets
Inventories	4.5	20,473	9,688
Trade and other receivables	4.2	26,463	54,562
Current tax receivable	6.3.1	80,409	-
Cash and cash equivalents	4.1	194,598	211,980
		321,943	276,230
Total assets		816,456	613,684
Equity
Share capital and share premium	5.4	9,464	9,464
Other equity	5.5	3,672	-
Other reserves	5.6	60,239	59,987
Retained earnings		8,580	33,261
Total equity		81,955	102,712
Non-current liabilities
Abandonment provision	2.3	209,041	123,503
Bond debt	5.1	215,722	80,800
Deferred tax liabilities	6.2.1	130,453	118,325
Other non-current liabilities	4.4	613	4,197
		555,829	326,825
Current liabilities
Trade payables and accruals	4.3	40,256	21,317
Other current liabilities	4.4	5,627	17,111
Current tax payable	6.3.2	128,616	143,134
Abandonment provision	2.3	4,173	2,585
		178,672	184,147
Total liabilities		734,501	510,972
Total equity and liabilities		816,456	613,684

A reclassification to the presentation of certain prior period amounts has been made - see note 1.5.

The notes below are an integral part of these Financial Statements and were approved by the Board of Directors on 10 May 2024.

Andrew Austin Executive Chairman

Consolidated statement of changes in equity

€'000	Share capital and share premium (note 5.4)	Other equity (note 5.5)	Other reserves (note 5.6)	Retained earnings	Total equity
At 1 January 2022	103,808	-	9,226	(42,463)	70,571
Profit for the period	-	-	-	25,961	25,961
Other comprehensive income	-	-	5,847	-	5,847
Total comprehensive income for the period	-	-	5,847	25,961	31,808
Capital reduction	(35,266)	-	(14,734)	50,000	-
Share-based payments	-	-	538	-	538
Capital reorganisation	(59,078)	-	59,110	(237)	(205)
At 31 December 2022	9,464	-	59,987	33,261	102,712
Loss for the period	-	-	-	(24,681)	(24,681)
Other comprehensive income	-	-	93	-	93
Total comprehensive income for the period	-	-	93	(24,681)	(24,588)
Share-based payments (note 3.4)	-	-	159	-	159
Issue of warrants (note 5.5)	-	3,672	-	-	3,672
At 31 December 2023	9,464	3,672	60,239	8,580	81,955

Consolidated cash flow statement

€'000	Note	Year ended 31 December 2023	Year ended 31 December 2022
Cash flows from operating activities:
(Loss)/profit for the period after tax		(24,681)	25,961
Tax (credit)/charge	6.1	(21,177)	228,164
Net finance costs	3.5	7,851	22,131
Depreciation and amortisation	2.4, 2.5	99,230	83,234
Impairment	2.6	59,023	44,547
Change in fair value and releases of contingent consideration	2.8.2	(3,355)	(26,993)
Share-based payment expense	3.4	159	538
Income tax paid		(33,794)	(65,729)
Income tax received		72,101	-
Interest income received		9,270	229
Abandonment costs paid	2.3	(1,941)	(2,319)
Decrease/(increase) in trade and other receivables		36,867	(1,382)
Decrease in trade and other payables		(1,131)	(13,094)
Decrease/(increase) in inventories		4,402	(4,717)
Movement in other working capital items		335	132
Net cash flow from operating activities		203,159	290,702
Cash flows from investing activities:
Payments to acquire tangible and intangible fixed assets		(119,318)	(19,454)
Net cash acquired in Mime Acquisition	2.8	7,284	-
Consideration paid for GLA Acquisition	2.8.1	(16,219)	(40,047)
Contingent consideration payments	2.8.2	-	(7,500)
Net cash flow from investing activities		(128,253)	(67,001)
Cash flows from financing activities:
Interest paid		(11,720)	(11,566)
Repurchase and redemption of bond debt	5.1.1	(83,599)	(71,773)
Lease repayments and other financing cash flows		(1,296)	(477)
Net cash flow from financing activities		(96,615)	(83,816)
(Decrease)/increase in cash and cash equivalents		(21,709)	139,885
Cash and cash equivalents at start of period	4.1	211,980	77,288
Effects of foreign exchange rate changes		4,327	(5,193)
Cash and cash equivalents at end of period	4.1	194,598	211,980

A reclassification to the presentation of certain prior period amounts has been made - see note 1.5.

Notes to the Consolidated Financial Statements

Section 1 General information and basis of preparation

Kistos Holdings plc (the 'Company') is a public company, limited by shares, incorporated and domiciled in the United Kingdom and registered in England and Wales under the Companies Act 2006 (registered company number 14490676). The nature of the Company and its consolidated subsidiaries' (together, the 'Group') operations and principal activity is the exploration, development and production of gas and other hydrocarbon reserves principally in the North Sea and creating value for its shareholders through the acquisition and management of companies or businesses in the energy sector.

1.1 Basis of preparation and consolidation

The Financial Statements have been prepared under the historical cost convention (except for derivative financial instruments and certain financial liabilities, which have been measured at fair value) in accordance with UK-adopted International Accounting Standards, in conformity with the requirements of the Companies Act 2006 and in accordance with the requirements of the Alternative Investment Market (AIM) Rules.

These Financial Statements represent results from continuing operations, there being no discontinued operations in the periods presented.

The accounting period of these consolidated Financial Statements is the calendar year 2023, which ended at the balance sheet date of 31 December 2023. The comparative period is the calendar year 2022, ending at the balance sheet date of 31 December 2022.

On 22 December 2022, by means of a Scheme of Arrangement, the Company became the new parent company for the Kistos Group of companies; the previous parent company being Kistos plc (a company registered in England and Wales under the Companies Act 2006 with registered company number 12949154). Following the Scheme of Arrangement, shareholders in Kistos plc received the same number and nominal value of Kistos Holdings plc ordinary shares. As the owners of the original parent had the same absolute and relative interests in the net assets of the original group and the new group immediately before and after the reorganisation, these comparative period of these consolidated Financial Statements is presented as if the Company headed the new group for all of the comparative reporting period. The change in parent company and legal capital of the group was reflected in the statement of changes in equity.

1.2 Going concern

Significant judgement - presumption of going concern

These 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 G&A expenditure, committed and sanctioned capital expenditure, foreign exchange rates and the timing and quantum of future tax payments and receipts.

Based on the judgements set out below, which includes consideration of both reasonably plausible downside scenarios, and mitigating actions management could take, these Financial Statements have been prepared on a going concern basis.

The Parent Company has minimal trade and its going concern assessment has been performed as part of the Group's going concern assessment. The Group's cash balances as at the end of April 2024 was €80 million. To assess the Group's ability to continue as a going concern, management evaluated cash flow forecasts for the period to June 2025 (the going concern period), by preparing a base case forecast and considering reasonably plausible sensitivities and mitigating actions that could be undertaken by the Group.

The base case going concern assessment assumed:

· First oil from the Jotun FPSO in the fourth quarter of 2024, in line with the current operator forecast and timetable, resulting in a cash outflow of $45 million on the Hybrid Bond in January 2025.

· 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 approximately €80 million is received in December 2024 in respect of Norwegian tax losses incurred in 2023.

· 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 (in respect of cover that needs to be in place for 2025).

· Completion of the Gas Storage Acquisition on 23 April 2024, for cash consideration of £25 million less closing working capital adjustments and including estimated incremental costs of integration.

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

· 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 76p/therm, €30/MWh and $83/bbl across the going concern period).

The base case forecast indicated that the Group would be able to maintain a sufficient amount of 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.

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. A return in respect of this tax is required to be filed no later than 31 May 2024, along with the payment of any tax due. As set out in note 6.4, the Group believes that there is an argument 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 would 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 Dutch Tax Authorities demand an earlier payment, or require payment prior to any appeal being admitted, this would have a further material adverse effect on the Group's liquidity (as illustrated in the reverse stress tests section below).

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 €81 million, which the Group satisfied via the purchase of surety bonds at an approximate cost of €2.5 million. The next redetermination will take place in June 2024, with renewed surety bonds (or other arrangements, if applicable) to be put in place by the end of 2024 will be for cover of an estimated obligation of €125 million . As part of the going concern assessment the Directors sought advice from surety bond brokers over the Group's ability to renew surety bonds given the combined impact of lower commodity prices, and higher tax and inflation rates adversely impacting the calculation of the amount of security required. 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, significantly reducing available liquidity. Based on the advice received from the surety bond providers, the Directors are of the view that the surety market will continue to provide security up to the current DSA provisions and those required in the foreseeable future.

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;

· a delay in first oil from the Jotun FPSO to summer 2025 which would result in lower production rates in Norway throughout the latter half of the going concern period, an increase to capital expenditure incurred, but no cash outflow in relation to the Hybrid Bond (as, under the bond terms outlined in note 5.1 and 2.8.1, the Hybrid Bond will be cancelled in its entirety if the first oil milestone is not met by 31 May 2025);

· adverse movement in foreign exchange rates, and

· a reduction to forecast cashflows generated from the Gas Storage Acquisition.

The outcome of applying one or more of these reasonably plausible scenarios against the base case indicated that during the fourth quarter of 2024 (prior to receiving a tax repayment of c.€80 million in Norway) the Group could breach its $10 million minimum liquidity covenant under the bonds issued by Kistos Energy Norway or fail to maintain appropriate liquidity to continue to meet day-to-day working capital requirements.

Reverse stress tests were also performed, which showed:

· A reduction in either sales volume or price assumption of approximately 15% (compared to the base case forecast) for the remainder of the going concern period, with all other factors held constant, would result in the liquidity covenants similarly being breached in November 2024.

· An increase to 2024 capital expenditure in Norway of approximately 20% would give rise to a similar outcome.

· If, prior to November 2024, the estimated DSA obligations were required to be fully covered in cash (with all other factors held constant), the resulting shortfall could be greater than €80 million.

· If, prior to November 2024, or the Solidarity Contribution Tax was required to be paid, including estimated interest, (with all other factors held constant) the resulting shortfall could be greater than €20 million.

The Group has also 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 prior to the receipt of the material tax receivable noted above. 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 5.2), for which $60 million (€56 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). 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.

Due to the potential for one or more of the reasonably plausible downside scenarios occurring, along with the uncertainties around the payment of any Solidarity Contribution Tax and the ability to secure the surety bonds to fund the DSAs, the Group would be dependent on successfully completing a tap issue of the KENO02 bond, securing another financing facility, and/or raising equity, which are not guaranteed or wholly within Director's control. This indicates a material uncertainty exists which may cast significant doubt about the Group's and ultimate parent company's) continued ability to operate as a going concern and therefore, the Group may be unable to realise its assets and discharge its liabilities in the normal course of business.

These consolidated Financial Statements do not include any adjustments that may result from the outcome of these uncertainties

1.3 Significant events and changes in the period

The financial performance and position of the group was significantly affected by the following events and changes during the period:

· The acquisition of Mime Petroleum AS (Mime), subsequently renamed Kistos Energy (Norway) AS (KENAS), in May 2023, resulting in additions of, among other items, €126 million of fixed assets, €105 million of current tax receivables, €68 million of abandonment liabilities, €39 million of goodwill and €204 million of debt recognised at their estimated fair values on acquisition (note 2.8).

· Impairment charges of €43 million in the UK segment following the Benriach well drilled during the period proving to be sub-commercial and the relinquishment of certain exploration licences (note 2.6.3).

· A goodwill impairment of €3 million relating to the UK exploration cash-generating unit (CGU) as a result of the above.

· Redemption in full (at a premium) of the two bonds issued by the Group's Dutch subsidiary, Kistos NL2 BV, resulting in a cash outflow of €84 million and a loss on redemption of €2 million (note 5.1.1).

· A decrease in average realised oil and gas sales prices and therefore significantly lower revenue as compared to the prior period (note 2.1).

· An impairment charge of €13 million relating to production assets in the Netherlands segment as a result of changes to commodity prices and a reduction to estimated reserves (note 2.6.1).

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.

Significant judgement - functional currency of Kistos Energy (Norway) AS

Under IAS 21 'The Effects of Changes in Foreign Exchange Rates' management is required to exercise judgement when determining an entity's functional currency, which is defined as "the currency of the primary economic environment in which the entity operates". Sales revenue and debt issued by the entity is denominated in United States Dollars (USD), whereas operating expenditure, capital expenditure, G&A and tax receivables are denominated primarily in Norwegian Krone (NOK). Furthermore, day-to-day working capital funding is provided by the Group in NOK. Having taken the factors and requirements in IAS 21 into account, management has determined the functional currency of Kistos Energy (Norway) AS to be NOK. If a different functional currency was chosen, this would affect the volatility of revenue and operating profit arising from exchange rate movements, determine which transactions could and could not be hedged, influence the identification of embedded currency derivatives and potentially give rise to temporary differences impacting profit or loss.

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).

These Financial Statements are presented in EUR, a currency different to the functional currency of the reporting entity (which is GBP). All amounts have been rounded to the nearest thousand EUR, unless otherwise stated.

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

· Assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet.

· Income and expenses for each income statement are translated at average exchange rates for the period.

· All resulting exchange differences are recognised in 'Other comprehensive income'.

Goodwill and fair value adjustments arising on the acquisition of a foreign operation are treated as assets and liabilities of the foreign operation and translated at the closing rate.

1.5 Material accounting policies

The Group adopted Disclosure of Accounting Policies (Amendments to IAS 1 and IFRS Practice Statement 2) from 1 January 2023. The adoption of these changes has not had any impact on the Group's accounting policies but does impact certain accounting policy information disclosed in its Financial Statements. The amendments require the disclosure of 'material' rather than 'significant' accounting policies and provide guidance as to the application of materiality to the disclosure of accounting policies, with the aim of providing useful, entity-specific accounting policy information. These amendments did not result in changes to accounting policies but have impacted the accounting policy information disclosed in this section.

Information concerning the Group's accounting policies is now disclosed in the relevant section of the Financial Statements if one or more of the following applies:

· There has been a change in accounting policies during the period.

· An accounting policy has been chosen from a set of alternatives under IFRS.

· An accounting policy has been derived using the general guidance in IAS 8 (in the absence of specific IFRS requirements).

· An accounting policy requires the application of significant judgement or assumptions.

· The accounting requirements for a transaction or event are complex.

The group has applies its accounting policies consistently throughout the current and prior periods. A minor reclassification has been made to the presentation of certain line items in the Financial Statements and the notes:

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

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

1.6 New and amended accounting standards adopted by the Group

The Group has applied the following new accounting standards, amendments and interpretations for the first time:

· IFRS 17 'Insurance Contracts'.

· Definition of Accounting Estimates (Amendments to IAS 8).

· International Tax Reform - Pillar Two Model Rules (Amendments to IAS 12).

· Deferred Tax related to Assets and Liabilities arising from a Single Transaction (Amendments to IAS 12).

· Disclosure of Accounting Policies (Amendments to IAS 1 and IFRS Practice Statement 2).

The group has elected to adopt the following amendments early:

· Classification of Liabilities with covenants as Current or Non-current (Amendments to IAS 1).

International Tax Reform - Pillar Two Model Rules (Amendments to IAS 12) provides a temporary exemption from deferred tax accounting for the top-up taxes and apply retrospectively. In July 2023, the UK government enacted legislation to implement the Pillar Two rules. However, as the Group is not currently in scope of the Rules (due to it having global revenues of less than €750 million) the retrospective application has no impact of the Group's Financial Statements.

The adoption of changes and amendments above has not had any material impact on the disclosure or on the amounts reported in the Financial Statements, nor are they expected to significantly affect future periods.

1.7 New and amended accounting standards not yet adopted

A number of other new and amended accounting standards and interpretations have been published that are not mandatory for the reporting period ended 31 December 2023, nor have they been early adopted. These standards and interpretations are not expected to have a material impact on the consolidated Financial Statements.

1.8 Accounting judgements and major sources of estimation uncertainty

In the application of the Group's accounting policies, the Directors are required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only the period, or in the period of the revision and future periods if the revision affects both current and future periods.

The critical judgements, apart from those involving estimations (which are dealt with separately below), that the Directors have made in the process of applying the Group's accounting policies and that have the most significant effects on the amounts recognised in the Financial Statements are:

· Determining the functional currency of Kistos Energy (Norway) AS (note 1.4);

· The assessment of borrowing costs to be capitalised (note 2.4);

· The identification of impairment indicators for assets and goodwill (note 2.6);

· The ongoing accounting treatment of the Hybrid Bond (note 5.1); and

· Uncertain tax positions (note 6.4).

The assumptions concerning the future, and other major sources of estimation uncertainty at the balance sheet date that may have a significant risk of causing a material adjustment to the carrying amount of assets and liabilities within the next financial year, are:

· Estimated future cash flows from assets used as basis for impairment testing for fixed assets and goodwill (note 2.6);

· Estimated quantity of hydrocarbon reserves and contingent resources (section 2);

· The estimated cost for abandonment provisions (note 2.3); and

· The presumption of going concern (note 1.2).

1.9 Impact of climate change and energy transition on accounting judgements and major sources of estimation uncertainty

The Directors have taken into account climate change and the desire by national and international bodies to transition towards a lower carbon economy were considered in preparing these consolidated Financial Statements. Most immediately, the energy transition is likely to impact future gas and oil prices which in turn may affect the recoverable amount of the Group's assets, its ability to raise finance, income tax and royalties and operating and capital costs. The estimate of future cash flows from assets, which includes management's best estimate of future oil prices, is considered a key source of estimation uncertainty.

Under current forecasts assuming the assets in their current condition, the Group's UK and Dutch oil and gas assets are likely to be fully depreciated within five years, during which timeframe it is expected that global demand for gas and oil will remain robust. Accordingly, the impact of climate change on expected useful lives of those assets is not considered to be a significant judgement or estimate.

The Group's Norwegian assets are anticipated to have a remaining useful life of 25-30 years, during which period the energy transition could significantly impact supply and demand for oil and gas and therefore future commodity prices. In order to estimate the sensitivity on this, management undertook two additional sensitivity scenarios to demonstrate the potential impact of energy transition and/or net zero policies on the carrying value of the Group's assets. These scenarios were based on the International Energy Agency's "World Energy Outlook 2023" report.

The two scenarios modelled were:

· the "Announced Pledges" scenario, which assume that governments will meet, in full and on time, all of the climate-related commitments that they have announced, including longer term net zero emissions targets; and

· the "Net Zero Emissions by 2050" scenario, which portrays a pathway for the energy sector to help limit the global temperature rise to 1.5 °C above pre-industrial levels in 2100 (with at least a 50% probability) with limited overshoot.

In both scenarios, management's assumptions over commodity prices for 2024, and 2025 was held at the same level as used in the impairment test undertaken (note 2.6.2) before aligning, on a declining straight-line basis, to the prices indicated in the table below. The estimated impact of these scenarios is as follows:

Scenario	2030 crude oil price ($/bbl real terms)	2050 crude oil price ($/bbl real terms)	Estimated impairment charge (€m)
Announced Pledges	74	60	-
Net Zero Emissions by 2050	42	25	15

In addition to oil and gas assets, climate change and energy transition could adversely impact the future development or viability of intangible exploration and evaluation assets. The existence of impairment triggers for such assets under IFRS 6 is considered a critical accounting judgement (see note 2.6).

Section 2 Gas and oil operations

Critical judgements and key sources of estimation uncertainty applicable to this section as a whole

Key source of estimation uncertainty - estimation of reserves and contingent resources

Reserves and contingent resources are those hydrocarbons that can be economically extracted from the Group's licence interests. The Group's reserves and contingent resources have been estimated based on information compiled by operators of the licence interests, other qualified persons, and updated and refined by the Group's internal experts and external contractors. These estimates use standard recognised evaluation techniques and include geological and reservoir information (as updated from data obtained through operation of a field), capital expenditure, operating costs and decommissioning estimates. These inputs are validated where possible against analogue reservoirs, and actual historical reservoir and production performance.

Changes to reserves estimates may significantly impact the financial position and performance of the Group. This could include a significant change in the depreciation charge for fixed assets, the timing (and carrying value) of abandonment provisions, the results of any impairment testing performed and the recognition and carrying value of any deferred tax assets.

2.1 Revenue

Accounting policy

Revenue from contracts with customers is measured based on the transaction price specified in a contract with the customer, being based on quoted market prices for the gas or liquids. All revenue is measured at a point in time, being that point at which the Group meets its promise to transfer control of a quantity of gas or liquids to a customer. For gas, control is transferred once the hydrocarbons pass a specified delivery point in a pipeline. For liquids sales, control is transferred in accordance with the incoterms specified in the contract. Adjustments to sales prices arising from settlement of provisional pricing arrangements are recognised as a debit or credit to revenue and not separated or treated as an embedded derivative.

Where compensation is received as part of a claim under loss of production insurance, amounts receivable are presented within Other income and not within Revenue. Subsequent remeasurements to compensation, favourable or adverse, are also presented within Other income.

€'000
Year ended 31 December 2023
	Netherlands	Norway	UK	Total
Sales of liquids	1,298	40,722	14,107	56,127
Sales of natural gas	65,881	-	84,989	150,870
Total revenue from contracts with customers	67,179	40,722	99,096	206,997

Year ended 31 December 2022
	Netherlands	Norway	UK	Total
Sales of liquids	-	-	-	-
Sales of natural gas	285,053	-	126,459	411,512
Total revenue from contracts with customers	285,053	-	126,459	411,512

All Norway segment revenue in the current year was derived from a single external customer. Revenues from transactions with another single external customer amounted to €135 million across the UK and Netherlands segments.

In the prior period, revenues from transactions with one single external customer in the Netherlands segment amounted to €285 million and revenues from transactions with another single external customer in the UK segment amounted to €126 million.

2.2 Segmental information

2.2.1 Segments and principal activities

The performance of the Group is monitored by the Executive Directors (comprising the Executive Chairman, Chief Executive Officer and Chief Financial Officer) on a geographical basis. For the period ended 31 December 2023 there are three (31 December 2022: two) reportable segments identified for the Group's business:

· Netherlands: Comprising the production and sale of gas and other hydrocarbons from the Q10-A field, and the costs associated with exploration, appraisal and development of other Dutch licences.

· Norway: Comprising the production of oil from interests in the Balder and Ringhorne Øst fields offshore Norway. This segment was created during the current period, following the completion of the acquisition in May 2023 (note 2.8).

· UK: Comprising the production and sale of gas and other hydrocarbons from the Group's interest in the GLA, and the costs associated with exploration, appraisal and development of other licences in the UK North Sea.

The key measure of performance used by the Executive Directors to review segment profit and loss is Adjusted EBITDA (note 2.2.2). They also receive disaggregated information concerning revenue, income tax charge and capital expenditure by segment on a regular basis. Information about other income statement measures, and the quantum of total assets and liabilities by segment, are not regularly provided to the Executive Directors. Transactions between segments are measured on the same basis as transactions with third parties and eliminate on consolidation.

2.2.2 Adjusted EBITDA

The Executive Directors use Adjusted EBITDA as a measure of profit or 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 which 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	Year ended 31 December 2023	Year ended 31 December 2022
Netherlands Adjusted EBITDA		48,438	270,626
Norway Adjusted EBITDA		24,123	-
UK Adjusted EBITDA		52,055	112,899
Head office costs and eliminations		(3,839)	(3,510)
Group Adjusted EBITDA		120,777	380,015
Development expenses		(1,146)	(1,752)
Share-based payment expense	3.4	(159)	(538)
Depreciation and amortisation	2.4, 2.5	(99,230)	(83,234)
Impairments	2.6	(59,023)	(44,547)
Transaction costs		(2,581)	(681)
Change in fair value and releases of contingent consideration	2.8.2	3,355	26,993
Operating (loss)/profit		(38,007)	276,256
Net finance costs	3.5	(7,851)	(22,131)
(Loss)/profit before tax		(45,858)	254,125

Transaction costs in the current period include amounts relating to the acquisition of Mime Petroleum. Transaction costs in the prior period relate to those costs incurred on the GLA Acquisition, and certain costs relation to a proposed combination with Serica Energy which did not proceed.

2.2.3 Other segmental and geographical disclosures

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Income tax charge/(credit) by segment:
Netherlands	4,861	135,414
Norway	19,377	-
UK	(33,317)	121,740
Unallocated and consolidation adjustments	(12,098)	(28,990)
Total	(21,177)	228,164

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Impairment charges by segment:
Netherlands	13,000	44,547
Norway	-	-
UK	46,023	-
Total	59,023	44,547

€'000	31 December 2023	31 December 2022
Non-current assets (other than financial instruments and deferred tax assets) by geographical region:
Netherlands	96,728	136,735
Norway	252,690	-
UK	143,014	200,052
Total	492,432	336,787

Revenue by segment is presented in note 2.1. The amount of inter-segment revenue was not material.

2.3 Abandonment provision

Source of estimation uncertainty - estimate of abandonment provisions

Decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to the relevant legal requirements, the expected cessation of production date of the related asset, the emergence of new technology or experiences at other assets. The expected timing, work scope, amount of expenditure and risk weighting may also change. Therefore, significant estimates and assumptions are made in determining the abandonment provision balance. The estimated decommissioning costs, and inflation and discount rates applied to derive the amounts recognised on the balance sheet, are reviewed at least annually, and the results of this review are then assessed alongside estimates from operators (where the Group is a non-operating partner in an arrangement).

Accounting policy

An abandonment provision for decommissioning is recognised when the related facilities or wells are installed. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related oil and gas asset. Where the Group acts as operator in a joint operation, only the Group's share of abandonment liabilities is recognised on the balance sheet. The provision recognised is the estimated cost of abandonment at the time of undertaking the work, discounted to its net present value, and is reassessed typically annually. Abandonment costs expected to be incurred within 12 months of the balance sheet date (and thus classified as current liabilities) are not discounted.

Changes in the estimated timing of abandonment or abandonment cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. Where the related item of property, plant and equipment has been fully impaired, the corresponding adjustment is recognised in profit and loss.

€'000	Abandonment provision
At 1 January 2023	126,088
Acquisitions (note 2.8)	68,273
Accretion expense	6,301
Changes in estimates to provisions	8,979
Utilisation	(1,941)
Effect of change to discount rate	(1,574)
Foreign exchange differences	7,088
At 31 December 2023	213,214
Of which:
Current	4,173
Non-current	209,041
Total	213,214

Abandonment provisions comprise:

· 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 pipelines and corresponding land from historic onshore assets;

· In Norway, plugging and abandonment of drilled wells on Ringhorne Øst and Balder, and removal of the Balder FPU and Ringhorne platform; and

· In the UK, 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 Shetland Gas Plant and restoration of the land upon which the plant is constructed.

The abandonment of the Q10-A wells and associated infrastructure is expected to take place between six and nine years from the balance sheet date, in 2025 for the Q11-B well (based on the regulatory requirement to abandon the well by that time as, at the balance sheet date, no extension of the suspension consent had been concluded) and within one year for the onshore pipelines and land restoration.

The abandonment of the UK fields, producing wells and associated infrastructure is expected to take place between five and fourteen years from the balance sheet based on current production and commodity price forecasts and sanctioned development plans. Certain suspended wells may be abandoned in 2025, pending regulatory clarification.

Abandonment of currently producing Norwegian infrastructure is anticipated to be abandoned between 2030 and 2050. The utilisation of provisions in the period relates to the onshore abandonment of the onshore Donkerbroek-Hemrik location and certain Ringhorne Øst wells.

Abandonment provisions are initially estimated in nominal terms, based on management's assessment of publicly available economic forecasts and determined using inflation rates of 2.0% to 2.5% (2022: 2.5%) and discount rates of 2.2% to 3.8% (2022: 2.5% to 3.5%). The changes in estimates to provisions arises primarily as a result of the increased inflation rate assumed.

The Group has in issue €81 million of surety bonds as at 31 December 2023 (2022: €27 million) 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 decommissioning of the fields.

2.4 Property, plant and equipment

Significant judgement - assessment of capitalised borrowing costs

For longer-term upstream development projects, judgement is applied in determining when substantially all the activities necessary to prepare assets for their intended use are complete. This judgement impacts when the Group ceases capitalisation of borrowing costs in accordance with IAS 23 'Borrowing costs'. Due to the nature of these projects, in particular, where the Group does not operate the assets or fields in question, it can be difficult to separately identify the costs attributable to developed reserves (which are ready for their intended use) from those costs attributable to undeveloped reserves.

The Norwegian assets, as outlined in note 2.8, were acquired in May 2023 for a consideration of €4 million, including €204 million of borrowings acquired as part of the acquisition. Management has judged that these fields included in the fair value of oil and gas assets acquired had commenced production and that substantially all activities necessary to prepare the assets for their intended use were complete prior to the date of acquisition. As a result, no borrowing costs have been capitalised in respect of these fields post-acquisition. Capital expenditures incurred subsequent to the date of acquisition have been funded through the Group's operating cash flows and existing cash balances rather than borrowings.

Accounting policy

All field development costs are capitalised as property, plant and equipment. Property, plant and equipment related to production activities are depreciated typically on the unit of production method, with the exception of the Group's interest in the Shetland Gas Plant, which is depreciated on a straight-line basis to the estimated cessation of production date of the related gas fields. Where a sidetrack from an original well is drilled, the costs of the original well are estimated and written off to the income statement. The cost of ordinary maintenance and repairs are expensed as incurred, whereas costs for improving and upgrading production facilities are added to the acquisition costs and depreciated together with the related asset.

All expenditure carried within each field is depreciated from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of reserves or resources at the end of the period plus the production in the period, generally on a field-by-field basis or by a group of fields which are reliant on common infrastructure. For larger ongoing development projects where both production and significant capital expenditure are ongoing, the unit of production ratio is calculated by reference to total expected project costs and total field 2P reserves. For other projects, where there is no currently approved FID in place to access 2P reserves, the unit of production ratio is calculated by reference to the net book value of assets attributable to the field(s) and total 1P reserves. Reserves used as the basis for unit of production depreciation may not be the same as reserves used by management for other internal and external reporting purposes.

€'000	Oil and gas assets	Other assets	Total
Cost
At 1 January 2022	185,413	325	185,738
Acquisition of business (note 2.8)	189,790	-	189,790
Additions	11,286	1,416	12,702
Disposals	(11,922)	(58)	(11,980)
Foreign exchange differences and other movements	(8,435)	-	(8,435)
At 31 December 2022	366,132	1,683	367,815
Acquisition of business	125,739	27	125,766
Additions	101,728	427	102,155
Foreign exchange differences and other movements	14,302	25	14,327
At 31 December 2023	607,901	2,162	610,063

Accumulated depreciation and impairment
At 1 January 2022	(14,395)	(116)	(14,511)
Depreciation charge for the period	(83,023)	(211)	(83,234)
Disposals	11,922	31	11,953
Impairment (note 2.6)	(286)	-	(286)
Foreign exchange differences and other movements	734	3	737
At 31 December 2022	(85,048)	(293)	(85,341)
Depreciation charge for the period	(98,613)	(414)	(99,027)
Impairment (note 2.6)	(13,000)	-	(13,000)
Foreign exchange differences and other movements	(794)	-	(794)
At 31 December 2023	(197,455)	(707)	(198,162)

Net book value at 31 December 2022	281,084	1,390	282,474
Net book value at 31 December 2023	410,446	1,455	411,901

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.

The 'Other' category includes office and IT equipment, including assets (primarily office leases) held as right-of-use assets (note 5.3).

In the prior period, 'Disposals' represented the removal of fully depreciated assets following abandonment work undertaken in the Netherlands.

2.5 Intangible assets and goodwill

Accounting policy

The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Costs incurred before a licence is awarded or obtained are expensed in the period. All licence acquisition, exploration and evaluation costs and directly attributable G&A costs are subsequently capitalised by well, field or exploration area, as appropriate. These costs are written off as exploration costs in the income statement unless commercial reserves have been established or the determination process has not been completed and there are no indications of impairment.

Specific indicators that would result in an immediate impairment include relinquishment of a licence and a sub-commercial drilling result. In such circumstances, subsequent expenditure on those licences is also recognised as an impairment in the income statement.

€'000	Goodwill	Exploration and evaluation assets	Other intangible assets	Total
Cost
At 1 January 2022	7,000	158,573	-	165,573
Acquisition of business (note 2.8)	10,913	32,923	-	43,836
Additions	-	8,660	-	8,660
Other	-	245	-	245
At 31 December 2022	17,913	200,401	-	218,314
Acquisition of business (note 2.8)	39,029	7,167	342	46,538
Additions	-	21,364	322	21,686
Foreign exchange differences	2,665	1,182	19	3,866
At 31 December 2023	59,607	230,114	683	290,404

Accumulated amortisation and impairment and impairments
At 1 January 2022	(7,000)	(112,802)	-	(119,802)
Impairment (note 2.6)	-	(44,261)	-	(44,261)
At 31 December 2022	(7,000)	(157,063)	-	(164,063)
Amortisation for the period	-	-	(203)	(203)
Impairment (note 2.6)	(3,480)	(42,543)	-	(46,023)
Foreign exchange differences	27	331	(4)	354
At 31 December 2023	(10,453)	(199,275)	(207)	(209,935)

Net book value at 31 December 2022	10,913	43,338	-	54,251
Net book value at 31 December 2023	49,154	30,839	476	80,469

Exploration and evaluation assets at 31 December 2023 include the 2C contingent resources comprising the Glendronach development in the UK, the Orion oil prospect on the Q10-A licence and the King/Prince prospects in Norway. The Group's interests in oil and gas licences are outlined in note 2.7.

2.6 Impairment of assets and goodwill

Critical judgement - identification of impairment indicators

Under IAS 36 the Group is required to consider if there are any indicators of impairment for property, plant and equipment. The judgement as to whether there are any indicators of impairment takes into consideration a number of internal and external factors, including changes in estimated reserves, significant adverse changes to production versus previous estimates made by management, changes in estimated future oil and gas prices, changes in estimated future capital and operating expenditure to develop and produce commercial reserves, and adverse changes in applicable tax regimes. Where indicators are present and an impairment test is required, the calculation of the recoverable amount requires estimation of its value in use (VIU) and/or fair value less costs of disposal (FVLCOD), using discounted cash flow models or other approaches. These assessments are performed on a cash-generating unit (CGU) basis, unless a lower level is deemed appropriate.

The judgement as to whether there are any indicators of impairment for intangible exploration assets is made by reference to, among other factors, the indicators outlined in IFRS 6, including the lack of planned or budgeted substantive expenditure on a licence, a lack of commercially viable reserves discovered, and other factors that indicate that the carrying amount of the intangible asset is unlikely to be recovered in full from successful development or by sale.

Key source of estimation uncertainty - estimated future cash flows used in impairment testing

In performing impairment tests, management uses discounted cash flow projections to estimate the fair value less costs of disposal of an asset's or CGU's recoverable amount. These forecasts include estimates of future production rates of gas and oil products, commodity prices and operating costs, and are thus subject to significant risk and uncertainty. Changes to external factors and internal developments and plans can significantly impact these projections, which could lead to additional impairments or reversals in future periods. Where applicable, a sensitivity analysis to the key estimates and assumptions is outlined below.

2.6.1 Netherlands segment impairments

The reduction in European gas prices, in conjunction with a downwards revision of reserves estimated to be in place at the Q10-A field, were considered by management to be impairment triggers for the Netherlands Production CGU. The CGU contains six producing wells at the Q10-A gas field, the Q10-A platform and associated infrastructure.

The recoverable amount was determined on a fair value less costs of disposal basis, using a discounted cash flow approach in line with how market participants would value the asset (and corresponding to how the Group would value similar assets), with the estimate therefore being classified as Level 3 in the fair value hierarchy due to a number of unobservable inputs used in the estimate.

The key assumptions used in the valuation were as follows:

· TTF gas prices of €43/MWh in 2024, €42/MWh in 2025 and €36/MWh in 2026 based on independent forecasts and estimates

· Gas production forecasts based on internal reservoir modelling until cessation of production in 2028 at which point the economic limit is reached.

· Operating expenditure based on forecasts and information provided by the operator of the P15-D platform, comprising the main component of operating costs

· A nominal post-tax discount rate of 8%

Costs of disposal were considered to be immaterial for the purposes of the impairment test. The recoverable amount of the CGU was estimated to be €50 million, giving rise to an impairment charge of €13 million recognised against oil and gas assets.

In the prior period, impairment charges of €45 million were recognised in the Netherlands segment primarily on exploration intangible assets, following, among other factors, the introduction of additional taxes by the Dutch tax authorities meaning there was no longer sufficient certainty over whether their carrying values could be recovered from future development. Included within these impairments was €7.5 million relating to the M10/11 licence which, at the previous balance sheet date, was not held by the Group as it was in the process of appealing its non-renewal by the Dutch authorities. The licence was re-awarded to the Group in July 2023. As evaluation, permitting and stakeholder engagement is still underway, it is not considered that there is sufficient certainty that its previous carrying value will be recovered in full and therefore no impairment reversal has been recognised.

The cumulative impairments recognised in the Netherlands segment since the acquisition of Tulip Oil in 2021 are €179 million.

2.6.2 Norway segment impairment test

The Norway production CGU, comprising the Group's working interests in the Balder and Ringhorne Øst fields and share of the Jotun FPSO is required to be tested for impairment because the goodwill allocated to it (being €39 million) was acquired in a business combination during the current reporting period.

The key assumptions used in the valuation were as follows:

· Production from the Balder and Ringhorne Øst continues until the end of field life at the end of the 2040s (with decommissioning occurring in the 2050s), beyond the current licence period which expires in 2030 on the basis that the Plan for Development and Operation (PDO) for Balder Future (which was approved by Norwegian Ministry of Energy in 2020) extends beyond this date. Due the nature of oil and gas production, is it not appropriate to extrapolate cash flows using a terminal value approach.

· Nominal oil prices of $84/bbl in 2024, $80/bbl in 2025, $76/bbl in 2026 rising to $81/bbl in 2030 and increasing by 2% per annum thereafter.

· USD/NOK exchange rate of 10.5, falling to 9.5 longer term.

· A nominal post-tax discount rate of 9% reflecting the specific risks relating to the segment and geographical region.

· Cost and production estimates reflecting the Operator's view of the field and development project as at 31 December 2023, as reflected in the 2024 Work Programme and Budget (which was approved by both Kistos and Vår Energi) and the Operator's longer-term Revised National Budget (RNB) submission. The 2024 budget approved assumes first oil from the Jotun FPSO in 2024.

The assumptions and values used are consistent with external sources of information (for example, publicly available commodity price forecasts) and budgets and assessments provided by the Operator of the assets.

The results of the impairment test were that the recoverable amount exceeded the carrying amount by €29 million and therefore no impairment charge was necessary.

Sensitivity analysis undertaken indicates that the following reasonably possible changes to certain key assumptions (after incorporating any consequential effects of that change on the other variables) would cause the recoverable amount to be equal to the carrying amount:

· A reduction in the commodity price curves used by 13%

· An increase of the discount rate to 17%

· A reduction of estimated production rates across the life of fields by 13%

· A reduction in the longer term USD/NOK exchange rate to 7.2

The sensitivity analysis undertaken indicated that a delay of first oil from the Jotun FPSO to 2025 is not anticipated to cause the recoverable amount to be lower than the carrying amount.

2.6.3 UK segment impairment test

The UK Production CGU, comprising the Group's working interest in the producing Laggan, Tormore, Edradour and Glenlivet fields and the Shetland Gas Plant, is required to be tested for impairment annually as goodwill allocated to the CGU (being €7 million) was acquired in a business combination.

The key assumptions used in the valuation were as follows:

· NBP gas prices of 100p/therm in 2024, 101p/therm in 2025 and 82p/therm in 2026 and 2027 based on independent forecasts and estimates prevailing at the balance sheet date;

· Costs and production estimates forecast by the asset operator, with the expected natural decline consistent with past performance, extending to the estimated cessation of production date in 2027 at which point a technical production limit is reached. Due the nature of oil and gas production, it is not appropriate to extrapolate cash flows using a terminal value approach.

· A nominal post-tax discount rate of 9% reflecting the specific risks relating to the segment and geographical region.

The results of the impairment test were that the recoverable amount exceeded the carrying amount by €2 million and therefore no impairment charge was necessary. It is estimated that a change to the following key assumptions would result in the recoverable amount being equal to the carrying amount:

· A reduction to the forward gas curve of approximately 4%

· A reduction to projected production rate of approximately 4%

· Use of a nominal post-tax discount rate of 13.5%

Within the UK segment Exploration CGU, the following impairments were recognised in the current period:

· €33 million relating to the Benriach licence, following the exploration well drilled during the period proving to be sub-commercial.

· €10 million relating to the Roseisle and Cardhu licences following the joint venture partners electing to relinquish the licences with effect from 1 December 2023.

· €3 million of goodwill associated with the Exploration CGU as a result of the licence impairments above.

2.7 Joint arrangements and licence interests

Accounting policy

The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classified as joint operations in accordance with IFRS 11. Where the Group is a non-operated partner, it accounts for its proportionate net share of the assets, liabilities, revenue and expenses of these joint operations, with amounts billed by operators to the Group also recognised within trade payables. Where the Group acts as operator to the joint operation, the net amount of the liabilities is presented on the Group's balance sheet, with amounts billed to the partners in respect of recovery of costs paid on behalf of the joint operation recognised within receivables.

The Group has the following interests in joint arrangements at the balance sheet date 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.

Field or licence	Country	Licence holder	Licence type	Status	Interest at 31 December 2023
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, Glendonrach and Glenlivet)	UK	Kistos Energy Limited	Production	Non-operated	20%
P2411 and P1453² (Benriach)	UK	Kistos Energy Limited	Exploration	Non-operated	25%
PL001	Norway	Kistos Energy (Norway) AS	Production	Non-operated	10%
PL027⁴	Norway	Kistos Energy (Norway) AS	Production	Non-operated	10%⁴
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 Awarded during the current period.

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

⁴ Licence PL027 comprises Balder and Ringhorne Øst fields. Kistos' share of the Ringhorne Øst unit is 7.4%.

2.8 Business combinations

Accounting policy

The Group accounts for business combinations using the acquisition method when the acquired set of activities and assets meets the definition of a business and control is transferred to the Group.

Any contingent consideration is measured at fair value at the date of acquisition, and discounted to present value if the consideration is expected to be settled more than 12 months from the balance sheet date. If an obligation to pay contingent consideration meets the definition of equity it is not remeasured, and any subsequent settlement is accounted for within equity. (The existence of a contingent settlement provision in an equity instrument issued as consideration for a business combination is not considered to preclude the fixed-for-fixed criteria of IAS 32.) Otherwise, contingent consideration is remeasured at fair value at each reporting date and subsequent changes in the fair value are recognised in profit or loss presented in a separate line on the face of the income statement.

On 23 May 2023, the Group completed the acquisition 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 (the 'Mime Acquisition'). The primary purposes of the acquisition were to gain entry into oil and gas activities on the Norwegian Continental Shelf (NCS) and to increase and diversify the Group's hydrocarbon production, reserves and contingent resources.

The acquisition consideration, management's assessment of the fair value of net assets acquired, and subsequent goodwill arising are as follows:

€'000	At acquisition date
Consideration:
Cash¹	-
Fair value of warrants issued	3,672
Total consideration	3,672
Net assets acquired:
Property, plant and equipment	125,766
Intangible assets	7,509
Trade and other payables and accruals	(23,456)
Other net working capital	4,075
Inventory	14,052
Tax receivable	105,052
Cash and cash equivalents	7,284
Bond debt	(203,671)
Abandonment provisions	(68,273)
Deferred tax liabilities	(3,695)
Goodwill	39,029
Total net assets acquired	3,672

¹ The cash consideration payable was $1.

Transaction costs of €3 million were incurred, recognised within General and administrative expenses within the income statement, and within operating cashflows in the cash flow statement. The fair value of receivables acquired (included within 'Net working capital') was estimated to be equal to the gross contractual amounts receivable.

As part of the consideration, 5.5 million warrants over shares in Kistos Holdings plc were issued to the vendor with an exercise price of 385p. 3.6 million of these warrants can be exercised until 18 April 2028, and 1.9 million can be exercised only between 30 June 2025 and 18 April 2028, but are subject to cancellation as described below. The fair value of warrants was estimated using a Black Scholes model and the Group's share price at the acquisition date, adjusted for the estimated probability of issuance; and are recognised within Other equity on the balance sheet.

As part of the completion of the transaction, the terms of the acquiree's bonds were amended. A summary of the bonds acquired is disclosed in note 5.1.

Goodwill arises primarily from the requirements to recognise deferred tax on the difference between the fair value and the tax base of the assets acquired. This fair value adjustment is not tax deductible and therefore results in a net deferred tax liability and corresponding entry to goodwill. The goodwill itself is not deductible for tax purposes.

The Mime Acquisition contributed €41 million of revenue and a loss after tax of €9 million for the period from acquisition date until 31 December 2023. If the acquisition had completed on 1 January 2023, consolidated revenue for the Group would have been €223 million and the consolidated loss after tax is estimated to have been €57 million. The latter has been estimated as if the fair value adjustments to fixed assets recognised at the acquisition date had occurred at the beginning of the reporting period, but no changes to the timing or nature of debt restructurings that occurred in the pro forma period. The impact to the non-IFRS measure Adjusted EBITDA as if the acquisition had completed on 1 January 2023 is disclosed in Appendix B1.

2.8.1 Acquisition in prior period

On 10 July 2022, the Group completed the acquisition 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; all comprising working interests in unincorporated joint operations (together, the GLA Acquisition). The headline consideration was $125 million based on an effective economic date of 1 January 2022, with the final firm consideration payment being reduced from $125 million by the post-tax cashflows generated from the assets between the effective economic date and the completion date (and other adjustments). The primary reasons for the acquisition were to diversify the Group's production base by gaining exposure to the UK North Sea and potential exploration upside.

The acquisition consideration, management's assessment of the net assets acquired, and subsequent goodwill arising were as follows:

€'000	At acquisition
Consideration:
Cash	40,047
Contingent consideration	38,029
Total consideration	78,076
Net assets acquired:
Property, plant and equipment	189,790
Exploration and evaluation assets	32,923
Investment in associates	61
Net working capital	(3,826)
Abandonment provisions	(115,004)
Net deferred tax liability	(36,781)
Goodwill	10,913
Total net assets acquired	78,076

Goodwill arose primarily from the requirements to recognise deferred tax on the difference between the fair value and the tax base of the assets acquired. This fair value uplift is not tax deductible and therefore results in a net deferred tax liability and corresponding entry to goodwill.

The contingent consideration comprised two elements:

· Up to a maximum of $40 million (€39.3 million) payable based on a formula including GLA gas production and average quoted gas prices through 2022. The fair value of this contingent consideration was assessed to be €34.9 million at the acquisition date. The actual amount of the contingent consideration was €16.2 million, which was settled in cash in March 2023.

· Upon the successful development of the Benriach area, consideration of $0.25 per MMBtu of the approved net 2P reserves following first gas. The fair value of this contingent consideration was assessed by management to be €3.1 million on acquisition. Following the exploration well drilled on Benriach during the year proving to be sub-commercial, the full amount of this contingent consideration was derecognised (€3.4 million at the point of derecognition) and a corresponding gain recognised in the income statement.

2.8.2 Movement in contingent consideration payable

The movement of contingent consideration balances is as follows:

€'000	GLA acquisition	Tulip Oil acquisition
At 1 January 2022	-	15,000
Recognised on acquisition	38,029	-
Contingent consideration paid in cash	-	(7,500)
Gain recognised following change in fair value	(19,493)	-
Accretion expense	153	-
Gain on derecognition	-	(7,500)
Foreign exchange differences	375	-
At 31 December 2022	19,064	-
Contingent consideration paid in cash	(16,219)	-
Gain on derecognition	(3,355)	-
Foreign exchange differences	510	-
At 31 December 2023	-	-

No contingent consideration was recognised as a result of the Mime Acquisition; however, the terms of the Hybrid Bond acquired contain provisions that are, in substance, render it as highly analogous to contingent consideration (see the significant judgement in note 5.1).

2.9 Commitments

The Group had outstanding contractual capital commitments at the reporting dates as follows:

€'000	31 December 2023	31 December 2022
Contractual commitments to acquire property, plant and equipment	91,430	2,553
Contractual commitments on intangible assets (including commitments on exploration assets)	93	27,483
Total	91,523	30,036

Section 3 Income statement

3.1 Earnings per share

	Year ended 31 December 2023	Year ended 31 December 2022
Consolidated (loss)/profit for the period attributable to shareholders of the Group (€'000)	(24,681)	25,961
Weighted average number of shares used in calculating basic earnings per share	82,863,743	82,863,743
Potential dilutive effect of:
Employee share options¹	-	135,989
Warrants²	-	-
Weighted average number of ordinary shares and potential ordinary shares used in calculating diluted earnings per share	82,863,743	82,999,732
Basic earnings per share (€)	(0.30)	0.31
Diluted earnings per share (€)	(0.30)	0.31

1 Employee share options are not dilutive for the current period as the average share price during the period did not exceed the exercise price of the options.

2 The warrants issued during the period as part consideration for the Mime Acquisition (note 2.8) are not dilutive as the average share price from the issue date of 23 May 2023 to the period end was below the exercise price.

3.2 General and administrative expenses

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Salary and related expenditure	9,179	6,598
Non-salary expenditure	4,778	3,048
Recovery and capitalisation of costs	(1,960)	(220)
Total general and administrative expenses	11,997	9,426

3.3 Employee benefit expenses

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Wages and salaries	7,844	6,286
Social security and pension costs	1,300	910
Equity-settled share-based payment expense (note 3.4)	159	538
Total employee benefit expenses	9,303	7,734

At 31 December 2023, the Group employed 33 people (31 December 2022: 24).

The monthly average number of full-time equivalent employees in the Group, excluding non-Executive Directors, is as follows:

	Year ended 31 December 2023	Year ended 31 December 2022
Technical	12	14
Finance, legal and support	10	7
Management	7	3
Total	29	24

3.4 Share-based payment arrangements

The Group has in place share option schemes for certain employees across its subsidiaries that are accounted for as equity-settled share-based payments. The total charge in respect of share-based payments was €0.2 million (2022: €0.5 million).

The total number of share options outstanding at 31 December 2023 was 166,560 (31 December 2022: 191,068), which have exercise prices in the range of 273-441p/share (31 December 2022: 273-343p/share). The closing share price of the Group's Ordinary Shares at 31 December 2023 was 165p.

No share options are in place for Directors.

3.5 Interest and other net finance costs

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Bank interest income	7,446	267
Interest on tax receivables	1,824	-
Other interest income	26	-
Total interest income	9,296	267
Bond interest	(23,620)	(10,543)
Other interest	-	(268)
Interest on tax	(4,238)	-
Surety bond interest	(913)	(472)
Total interest expenses	(28,771)	(11,283)
Accretion expense on abandonment provisions and other liabilities (note 2.3 and 2.8.2)	(6,301)	(2,028)
Accretion expense on lease liabilities	(101)	(42)
Amortisation of bond costs (note 5.1)	(1,024)	(1,062)
Remeasurement loss on Hybrid Bond (note 5.1)	(3,169)	-
Loss on bond repurchases (note 5.1.1)	(2,404)	(6,414)
Net foreign exchange gains on bond debt	24,218	-
Net other foreign exchange gains/(losses)	405	(1,569)
Total other net finance income/(costs)	11,624	(11,115)
Total net finance costs	(7,851)	(22,131)

Section 4 Working capital

4.1 Cash and cash equivalents

Cash and cash equivalents consist of bank accounts and restricted cash balances. Restricted funds relate to a bank guarantee for the office leases and employee withholding taxes in Norway. Under the terms of its bonds, the Group is required to maintain a minimum liquidity balance of $10 million until first oil from the Jotun FPSO (note 5.1).

€'000	31 December 2023	31 December 2022
Bank accounts	194,431	211,958
Restricted funds	167	22
Cash and cash equivalents	194,598	211,980

4.2 Trade and other receivables

€'000	31 December 2023	31 December 2022
Trade receivables	8,287	-
Accrued income	8,892	47,962
Receivables due from joint operation partner	591	3,198
Other receivables and cash overcalls	1,807	1,594
Prepayments	6,262	679
VAT receivable	624	1,129
Total trade and other receivables	26,463	54,562

Accrued income represents amounts due in respect of gas sales that had not been invoiced at the balance sheet date. All accrued income amounts had been invoiced and collected in full within one month of the corresponding reporting date. Information about the Company's exposure to credit risk and impairment losses for other short-term receivables is included in note 4.6.

4.3 Trade payables and accruals

€'000	31 December 2023	31 December 2022
Trade payables	6,179	7,271
Payables to joint operators	2,612	1,945
Accruals	31,465	12,101
Total trade payables and accruals	40,256	21,317

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. The carrying value of trade payables and other accrued expenses are considered to be fair value given their short-term nature. A reclassification to the prior period has been made in order to present 'Payables to joint operators' within 'Trade payables and accruals' (previously classified within 'Other liabilities').

4.4 Other liabilities

€'000	31 December 2023	31 December 2022
Bond interest payable	971	831
Salary and other payroll-related liabilities	981	202
Contingent consideration (note 2.8.2)	-	15,796
Lease liabilities	295	282
VAT payable	621	-
Overlift	1,673	-
Other	1,086	-
Other liabilities - current	5,627	17,111

Contingent consideration	-	3,268
Lease liabilities	613	929
Other liabilities - non-current	613	4,197

4.5 Inventory

Accounting policy

Liquids inventory (comprising crude oil and natural gas liquids) is held at the lower of cost and net realisable value. The cost of liquids inventory is the cost of production, including direct labour and materials, depreciation and a portion of operating costs and other overheads allocated based on the ratio of liquids to gas production, determined on a weighted average cost basis. Net realisable value of liquids inventory is based on the market price of equivalent liquids at the balance sheet date, adjusted if the sale of inventories after that date gives additional evidence about its net realisable value. The cost of liquids inventory is expensed in the period in which the related revenue is recognised.

For spares and supplies inventories cost is determined on a specific identification basis, including the cost of direct materials and (where applicable) direct labour and a proportion of overhead expenses. Items are classified as spares and supplies inventory where they are either standard parts, easily resalable or available for use on non-specific campaigns, and within property, plant and equipment or intangible exploration and evaluation assets where they are specialised parts intended for specific projects. Write downs to estimated net realisable value are made for slow moving, damaged or obsolete items, typically based on the ageing of stock.

€'000	31 December 2023	31 December 2022
Spares and supplies	11,791	3,896
Crude oil and natural gas liquids	8,682	5,792
Total inventory	20,473	9,688

The amount of inventory recognised as an expense in the current period was €9.6 million (2022: nil). The movement in inventory net realisable value provisions amounted to a charge of €1.3 million (2022: €0.8 million).

4.6 Financial instruments and financial risk management

Accounting policy

Where a financial instrument, such as the Hybrid Bond, contains both a compound instrument and contingent settlement provisions, the entire instrument is measured as a financial liability and not separated.

Gains or losses arising from changes to the remeasurement of the Hybrid Bond are recognised within 'Other net finance costs' in the income statement.

4.6.1 Financial risk management objectives

The Group is exposed to a variety of risks including commodity price risk, interest rate risk, credit risk, foreign currency risk and liquidity risk. The use of derivative financial instruments is governed by the Group's policies approved by the Kistos Board. Compliance with policies and exposure limits is monitored and reviewed internally on a regular basis. The Group does not enter into or trade financial instruments, including derivatives, for speculative purposes.

4.6.2 Financial assets and liabilities carried at fair value

At 31 December 2023, there were no financial assets or liabilities carried at fair value.

At 31 December 2022, the Group held one financial liability carried at fair value, being €19 million in respect of contingent consideration for the GLA Acquisition and classified as Level 3 in the fair value hierarchy. These contingent consideration balances were settled or released in full in the current year (note 2.8.2). There were no financial assets carried at fair value at 31 December 2022.

4.6.3 Risk management framework

The Kistos Board has overall responsibility for the establishment and oversight of the Group's risk management framework. The Kistos Board is responsible for developing and monitoring the Group's risk management policies.

The Group's risk management policies are established to identify and analyse the risks faced by the Group, to set appropriate risk limits and controls but also to monitor risks and adherence to limits. Risk management policies and systems are reviewed when needed to reflect changes in market conditions and the Group's activities. The Group aims to develop a disciplined and constructive control environment in which all employees understand their roles and obligations.

The Audit Committee oversees how management monitors compliance with the Group's risk management policies and procedures and reviews the adequacy of the risk management framework in relation to the risks faced by the Group.

4.6.4 Market risk

Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk for the Group has been assessed as comprising foreign exchange risk, interest rate risk and other commodity price risk.

Currency risk

Currency risk is the risk that fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates.

The Group operates within the Netherlands, UK and Norway and is therefore exposed to foreign exchange risk. Most of the Group's exposure to currency risk arises in Norway, where revenue receipts and bond debt are denominated in USD, whereas operating costs, tax receivables, working capital financing and the majority of capital expenditure is denominated in the local functional currency of NOK. Entities within the Group undertake transactions in currencies other than their functional currency, which gives rise to transactional currency risk. The Group manages this risk to an extent by holding certain amounts of cash in currencies other than the entity's functional currency to act as an economic hedge against foreign exchange movements; however, the Group does not currently have a formal currency risk management policy or enter into any currency hedges.

As at 31 December 2023, 17% of the Group's cash and cash equivalents was held in EUR (31 December 2022: 49%).

A 15% strengthening of USD relative to NOK at 31 December 2023 would have adversely impacted equity and profit and loss by approximately €24 million, with a corresponding 15% weakening positively impacting equity and profit and loss would have by approximately €24 million. This analysis assumes that all other variables, in particular interest rates, remain constant, and ignores any impact of forecast sales and/or expenses. The exposure to other foreign currency movements is not material.

The currency sensitivity analysis selected (USD to NOK) has changed from that used in the prior year (GBP to EUR) as, following the Mime Acquisition, the Group carries a material amount of bond debt denominated in a currency other than the issuing entity's functional currency and is therefore exposed to greater risk in respect of that currency pairing.

Interest rate risk

Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market interest rates.

The Group is exposed to interest rate movements through its cash and cash equivalents deposits which earn interest at variable interest rates. There is no interest rate exposure on the Group's borrowings as they carry fixed rates of interest (note 5.1).

For the period ended 31 December 2023, it is estimated that a 1% increase in interest rates would have increased the Group's profit after tax by approximately €2 million, and a 1% decrease would have reduced the Group's profit after tax by approximately €2 million. This sensitivity has been calculated only based on the average cash balances held and estimating an effective tax rate on interest income across the Group. The impact on equity would be the same as the impact on profit after tax.

Other price risks - commodity price risk

Commodity risk predominantly arises from the sale of natural gas and crude oil from the Group's interests in oil and gas licences, as the price realised from the sale of natural gas and crude oil is determined primarily by reference to quoted market prices on the day and/or month of delivery.

The Group has previously used derivatives to mitigate the commodity price risk associated with its underlying oil and gas revenues. Where such transactions are carried out, they are done based on the Company's guidelines.

In 2021, Kistos NL2 hedged a portion of monthly production from the Q10-A field (being the hedged item) at an amount of 100,000 MWh per month at a price of €25/MWh (being the hedged instrument) for the nine-month period from July 2021 to March 2022. The hedge was fully effective in the prior period.

As at 31 December 2023, the Group had no commodity price hedging arrangements in place.

The Group enters into other commodity contracts (such as purchases of carbon emission allowances, fuel and chemicals) in the normal course of business, which are not derivatives, and are recognised at cost when the transactions occur.

4.6.5 Credit risk

Credit risk is the risk that the Group will suffer a financial loss as a result of another party failing to discharge an obligation and predominantly arises from cash and other liquid investments deposited with banks and financial institutions, receivables from the sale of natural gas and other hydrocarbons, and receivables outstanding from its joint operation partner.

The Group has policies that cover the management of credit risk, including review of counterparty credit limits and specific transaction approvals. The Group's oil and gas sales are made to international oil market participants including the oil majors, trading houses and refineries. Joint operators are international major oil and gas market participants and entities wholly owned by the Dutch state. Material counterparty evaluations are conducted utilising international credit rating agency and financial assessments. Where considered appropriate, security in the form of trade finance instruments from financial institutions with appropriate credit ratings, such as letters of credit, guarantees and credit insurance, are obtained to mitigate the risks.

The Group held cash and cash equivalents of €195 million as at 31 December 2023 (2022: €212 million). As at 31 December 2023, over 99% of the Group's cash and cash equivalents (2022: over 99%) are held with bank and financial institution counterparties which have an investment grade credit rating and as such the Group considers that its cash and cash equivalents have low credit risk.

The carrying values of cash and cash equivalents and trade and other receivables (excluding prepayments) represent the Group's maximum exposure to credit risk at year end, as the Group has not recognised an allowance for credit losses in the current or prior period. The Group has no material financial assets that are past due.

4.6.6 Liquidity risk

Liquidity risk is the risk that the Group will encounter difficulty in meeting obligations associated with its financial liabilities that are settled by delivering cash or other financial assets.

The Group manages its liquidity risk using both short- and long-term cash flow projections, supplemented by debt financing plans and active portfolio management. Ultimate responsibility for liquidity risk management rests with the Kistos Board, which has established an appropriate liquidity risk management framework covering the Group's short-, medium- and long-term funding and liquidity management requirements.

Cash forecasts are regularly produced, and sensitivities run for different scenarios including, but not limited to, proposed acquisitions and/or disposals, changes in commodity prices, different production rates from the Group's producing assets and delays to development projects. In addition to the Group's operating cash flows, portfolio management opportunities are reviewed to potentially enhance the financial capability and flexibility of the Group.

The Group's financial liabilities comprise trade payables (note 4.3), other liabilities (note 4.4) and bond debt (note 5.1). The maturity analysis of financial liabilities is shown in note 4.7.

In addition to the amounts held on balance sheet, the Group has in issue €81 million of surety bonds as at 31 December 2023 (2022: €27 million) to cover its obligations under Decommissioning Security Agreements (DSAs) for future abandonment of the GLA fields and infrastructure. Should the Group be in default under the DSAs resulting in the bond provider being required to pay out on those bonds, the Group would be required to indemnify the providers by paying cash to cover their liability. If the surety market were to deteriorate such that the Group is unable to renew its bonds, then the Group would be required to satisfy its DSA obligations by transferring an equivalent amount of its cash into trust.

4.7 Maturity analysis of financial liabilities

The maturity analysis of contractual undiscounted cash flows for non-derivative financial liabilities is as follows:

€'000	Within 3 months	3 months to 1 year	1-5 years	More than 5 years	Total
Bond debt¹	1,272	3,917	295,237	-	300,426
Trade payables, accruals and other financial liabilities	42,947	-	-	-	42,947
Lease liabilities	92	274	735	-	1,101
At 31 December 2023	44,311	4,191	295,972	-	344,474

Bond debt	-	7,379	98,319	-	105,698
Contingent consideration	15,796	-	-	6,191	21,987
Trade payables, accruals and other financial liabilities	21,519	-	-	-	21,519
Lease liabilities	75	308	1,110	-	1,493
At 31 December 2022	37,390	7,687	99,429	6,191	150,697

Where cash flows are denominated in foreign currencies, the prevailing spot rate at the end of the period has been used to translate into the presentational currency.

1. Bond debt excludes the Hybrid Bond, which will have cash outflows in 2025 of either $45 million (payable within 3 months), $30 million (payable within 3 months to 1 year), $15 million (payable within 3 months to 1 year) or $nil depending on the timing of milestones achieved from the Jotun FPSO (note 5.1).

Section 5 Capital and debt

5.1 Bond debt

The Group has in issue bond debt as follows:

					31 December 2023		31 December 2022
Bond	Issuer	Currency	Coupon rate	Maturity date	Face value (issued currency)	Carrying amount €'000	Face value (issued currency)	Carrying amount €'000
KENO01	KENAS	USD	10.25%¹	November 2027	$116,809,148	90,655	-	-
KENO02	KENAS	USD	9.75%²	September 2026	$124,786,992	110,803	-	-
Hybrid Bond	KENAS	USD	n/a	March 2083³	$45,000,000	14,264	-	-
€90 million bond	Kistos NL2	EUR	8.75%	November 2024⁴	-	-	€21,572,000⁵	22,706
€60 million bond	Kistos NL2	EUR	9.15%	May 2026⁴	-	-	€60,000,000	60,000
Total €'000						215,722		82,706

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

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

3. Certain amounts of the Hybrid Bond will be cancelled for nil consideration should milestones relating to the Jotun FPSO not be met. If the milestones have not been met by 31 May 2025, the Hybrid Bond will be cancelled in its entirety.

4. These bonds were redeemed in full by exercise of call options in December 2023.

5. Net of €68.4 million of bonds held in treasury.

Significant judgement - accounting treatment of Hybrid Bond

Included within the bond debt acquired is the Hybrid Bond, payment of which is contingent on an operational milestone being met, being the offload of 500,000 barrels (gross) of Balder crude oil from the Jotun FPSO. The Hybrid Bond will be settled in full ($45 million) if the milestone is met by 31 December 2024. This will decline to $30 million if the milestone is met between 1 January 2025 and 28 February 2025, and to $15 million if the milestone is met between 1 March 2025 and 31 May 2025. If the milestone has not been met by 31 May 2025, the Hybrid Bond will be cancelled in its entirety and bondholders will instead be allocated 2.4 million warrants exercisable into ordinary shares of Kistos Holdings plc at a price of 385p each, exercisable between 30 June 2025 and 18 April 2028. Simultaneously, 1.9 million of the 5.5 million warrants issued to the vendor as consideration for the Mime Acquisition will be cancelled.

The Hybrid Bond is a financial liability and is measured at amortised cost. At each measurement date, the carrying value is re-estimated based on expected future cashflows which take into account the expectation and timing oof the milestones being met. Any remeasurement is recorded in profit or loss within finance costs.

The KENO01 and KENO02 bonds have minimum liquidity requirements of the issuer, being $10 million minimum liquidity, applicable from 1 January 2024 until first oil from the Jotun FPSO. The minimum liquidity requirement prior to 1 January 2024 was $5 million, and the issuer complied with the covenants at all times.

The Group has call options to redeem its 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 Repurchase of bonds

Accounting policy

Where debt instruments issued by the Group are repurchased, the financial liability is derecognised at the point at which cash consideration is settled, even if the associated instruments cannot be legally cancelled. Upon derecognition, the difference between the liability's carrying amount that has been derecognised and the consideration paid is recognised as a gain or loss in the within finance costs. Upon early settlement or redemption of bonds, any unamortised bond costs are released to the income statement at the point at which the entire instrument is extinguished rather than on a pro rata basis.

During 2023, the Group repurchased €4.9 million in nominal value of its €90 million bonds in the open market at an average price of 102%. Although the bonds could not be cancelled, the liability relating to the repurchased amount was treated as being extinguished.

In December 2023, the Group exercised its call options on the €60 million and remaining €16.8 million of the €90 million bonds; the applicable call price being 102.5%. Due to the bonds being repurchased at a premium, a total loss of €2 million was recognised, reconciled as follows:

	€'000
Cash consideration paid for repurchase of bond principal	83,599
Carrying value of bond derecognised	(81,195)
Loss on repurchase of bond	2,404

5.2 Reconciliation of liabilities arising from financing activities

€'000		Bond debt	Bond interest payable	Other liabilities	Total
At 1 January 2022		145,074	1,854	122	147,050
Financing cash flows		(71,773)	(11,566)	(209)	(83,548)
Non-cash movements:
Interest expense and amortisation of bond costs		1,085	10,543	-	11,628
Loss on bond repurchase		6,414	-	-	6,414
New leases entered into		-	-	1,297	1,297
At 31 December 2022		80,800	831	1,210	82,841
Financing cash flows		(83,599)	(11,720)	(383)	(95,702)
Non-cash movements:
Acquisitions (note 2.8)		203,671	7,402	-	211,073
	Issue of new bonds via payment-in-kind interest	15,052	(15,052)	-	-
Interest expense and amortisation of bond costs		5,414	19,230	101	24,745
Loss on bond repurchase		2,404	-	-	2,404
Remeasurement of Hybrid Bond		3,169	-	-	3,169
Foreign exchange differences		(11,189)	280	(21)	(10,930)
At 31 December 2023		215,722	971	907	217,600

5.3 Leases

Lease liabilities are included within Other liabilities on the balance sheet, and right-of-use assets are included within the Other category of Property, plant and equipment. The carrying value of right-of-use assets at 31 December 2023 was €0.9 million (31 December 2022: €1.2 million). The depreciation charge on right-of-use assets, cash outflow for leases and expenses relating to low-value and short-term leases was not material in either period presented.

In the prior period, additions of €1.3 million were made to right-of-use assets, primarily relating to the lease of the Group's new head office in London.

5.4 Share capital and premium

	Number of shares	Share capital (€'000)	Share premium (€'000)
At 1 January 2022	82,863,743	9,627	94,181
Issue and cancellation of bonus shares	-	-	14,734
Capital reduction	-	-	(50,000)
Capital reorganisation	-	(163)	(58,915)
At 31 December 2022	82,863,743	9,464	-
At 31 December 2023	82,863,743	9,464	-

Ordinary shares have a nominal value of £0.10 per share. The Group's policy is to manage a strong capital base so as to manage investor, creditor and market confidence, and to sustain growth of the business. Management monitors its return on capital. There are currently no covenants related to the equity of the Group.

Following approval by the Group's shareholders at the Annual General Meeting in June 2022 and subsequent sanction by the Court in October 2022, the full balance of the merger reserve in Kistos plc was allotted to share premium by means of a bonus share issue and cancellation. A capital reduction was then undertaken to reduce the share premium account of Kistos plc by €50 million with the corresponding credit to retained earnings. These transactions were undertaken in order to increase the distributable reserves of Kistos plc, the parent company of the consolidated group at the time.

In December 2022, the Group's shareholders and the High Court of Justice of England and Wales sanctioned a scheme of arrangement whereby Kistos Holdings plc, a newly incorporated entity, became the new ultimate parent company of the Group with shareholders receiving one Kistos Holdings plc share for each Kistos plc share held.

The share premium reserve represented amounts paid up on ordinary shares in excess of their nominal value. Following the capital reorganisation, the share premium account reflects that of Kistos Holdings plc, which is nil.

5.5 Other equity

Other equity comprises the Warrants reserve which has a balance of €3.7 million. This reserve arose on completion of the Mime Acquisition (note 2.8), whereby 5.5 million warrants were issued to the vendor as part of the consideration. The warrants allow the holder to subscribe to shares in Kistos Holdings plc at an exercise price of £3.85 per share.

Upon issue, the warrants were measured at fair value using a Black Scholes option pricing model, adjusted for probability of issuance, and are not subsequently remeasured.

5.6 Other reserves

Accounting policy

Where a capital reorganisation takes place resulting in a newly incorporated entity acquiring the existing Group, the new entity does not meet the definition of a business and the transaction is therefore outside the scope of IFRS 3. In such a transaction, the substance of the Group has not changed therefore the consolidated Financial Statements of the new entity are presented using the balances and values from the consolidated Financial Statements from the previous entity. The net assets of the new group remain the same as the existing group.

The movements in ordinary shares and other transactions impacting share capital, share premium and the merger and capital reorganisation reserve are as follows:

€'000	Merger reserve	Capital reorganisation reserve	Hedge reserve	Translation reserve	Share-based payment reserve	Total
At 1 January 2022	14,734	-	(5,890)	382	-	9,226
Other comprehensive income	-	-	5,890	(43)	-	5,847
Transactions with owners:
Issue and cancellation of bonus shares	(14,734)	-	-	-	-	(14,734)
Capital reorganisation	140,105	(80,995)	-	-	-	59,110
Equity-settled share-based payments	-	-	-	-	538	538
At 31 December 2022	140,105	(80,995)	-	339	538	59,987
Other comprehensive income	-	-	-	93	-	93
Transactions with owners:
Equity-settled share-based payments	-	-	-	-	159	159
At 31 December 2023	140,105	(80,995)	-	432	697	60,239

The merger reserve originally represented the difference between the value of shares in Kistos plc issued as part of the total consideration of the acquisition of Kistos NL1 and the nominal value per share. Following the capital reorganisation and creation of Kistos Holdings plc as the new parent entity of the Group, the merger reserve now represents the merger reserve of Kistos Holdings plc, being the difference between the amount at which the investment in Kistos plc was recorded and the aggregate nominal value of the shares in Kistos Holdings plc issued.

The capital reorganisation reserve arises only on consolidation and represents the difference between the equity structure of Kistos Holdings plc (as the new parent company of the Group) and the equity structure of Kistos plc (as the parent company of the Group) following the scheme of arrangement.

The hedge reserve is used to record the effective portion of gains or losses on derivatives qualifying as cash flow hedges. Amounts are subsequently reclassified to the income statement when the related hedges are realised.

The translation reserve comprises foreign currency differences arising from the translation of the Financial Statements of foreign operations.

The share-based payment reserve is used to record the grant-date fair value of share options issued to employees of the Group. corresponding entry to the share-based payment reserve is the charge of share-based payment expense (note 3.4).

Section 6 Tax

6.1 Tax charge or credit for the period

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Current tax:
Current tax (credit)/charge for current year	(21,995)	195,531
Prior period adjustments for current tax	(1,327)	-
Total current tax (credit)/charge	(23,322)	195,531
Deferred tax:
Origination and reversal of temporary differences	5,791	(30,321)
Imposition of Energy Profits Levy in the UK	-	62,954
Adjustments in respect of prior periods	(3,646)	-
Total deferred tax (credit)/charge	(2,145)	32,633
Total tax (credit)/charge	(21,177)	228,164

The income tax credit or charge for the period can be reconciled to the accounting profit or loss as follows:

€'000	Year ended 31 December 2023	Year ended 31 December 2022
(Loss)/profit before tax	(45,858)	254,125

Income tax credit/(charge) calculated at the domestic tax rate applicable to each entity's activities	29,494	(142,880)

Investment allowances and other enhanced deductions	9,611	7,471
Income and expenditure not taxable or deductible	(22,119)	21,799
Utilisation of losses	-	7,021
Deferred tax not provided and losses not recognised	175	(3,406)
Impact of Energy Profits Levy in the UK	-	(71,573)
Solidarity Contribution Tax charge (note 6.4)	-	(46,935)
Adjustments in respect of prior periods	4,973	-
Other (including changes to, and differences in, tax rates)	(957)	339
Tax credit/(charge)	21,177	(228,164)

Effective tax rate	46.2%	89.8%

The applicable domestic tax rates for the Group's activities are as follows:

	Year ended 31 December 2023	Year ended 31 December 2022
Netherlands	50%	50%¹
Norway	78%	n/a
United Kingdom	75%	65%
United Kingdom (non-ring fence activity)	23.5%	19%

1 Excluding impact of the Solidarity Contribution Tax charge.

6.2 Deferred tax

6.2.1 Deferred tax liabilities

The movement in the deferred tax liability account is as follows:

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Deferred tax liability at beginning of period	118,325	57,288
Recognised on acquisition (note 2.8)	3,695	36,781
Charged to income statement	3,511	25,594
Foreign exchange differences	4,922	(1,338)
Deferred tax liability at end of period	130,453	118,325

Deferred tax liabilities primarily comprise temporary differences arising on fixed assets.

6.2.2 Deferred tax assets

€'000	Tax losses	Provisions	Fixed assets and other	Total
At 1 January 2022	7,015	4,168	2,313	13,496
Charged to other comprehensive income	-	-	(5,891)	(5,891)
(Charged)/credited to income statement	(7,015)	(697)	673	(7,039)
At 31 December 2022	-	3,471	(2,905)	566
Credited to income statement	-	75	1,291	1,366
At 31 December 2023	-	3,546	(1,614)	1,932

In the prior period, deferred tax assets relating to tax losses related to Corporate Income Tax (CIT) and State Profit Share (SPS) losses in the Netherlands, losses which were fully utilised during the prior period.

Accumulated UK non-ring fence tax losses of €16 million have not been recognised due to the uncertainty of where future UK non-ring fence profits may arise from. SPS losses of €56 million in the Netherlands have not been recognised due to the uncertainty of future profits arising in the entity holding those losses. These losses can be carried forward indefinitely subject to the entity continuing to hold a production licence.

6.2.3 Changes to tax rates

In June 2023, the UK Government announced further changes to the Energy Profits Levy (EPL), introducing the Energy Security Investment Mechanism (ESIM) whereby if average oil and gas prices are sustained below $71.40/bbl and 54p/therm (adjusted annually by CPI) for a continuous period of six months then legislation will be introduced to remove EPL effective from that point. Based on management's assessment of future oil and gas prices, the ESIM is not anticipated to be triggered and therefore deferred tax balances have been measured on the basis of EPL applying until March 2028. In March 2024, the UK Government announced an extension of the Energy Profits Levy until March 2029. This extension has not yet been substantively enacted; however, given the economic life of the Group's UK oil and gas assets in their current condition and the status of future potential developments, this change is not anticipated to have a material impact to the Group's deferred taxation charge.

The tax rate applicable to UK entities outside of the ring-fence increased from 19% to 25% with effect from 1 April 2023.

6.3 Current tax

6.3.1 Current tax receivable

The Group has a current tax asset of €80 million wholly relating to tax losses incurred in Norway. This is anticipated to be received by the Group in December 2024, and accrues repayment interest (the current statutory rate being 4.5%) from 1 January 2024.

6.3.2 Current tax liabilities

The Group has current tax liabilities by segment as follows:

	31 December 2023	31 December 2022
Netherlands	49,919	77,627
Norway	-	-
United Kingdom	78,697	65,507
Total	128,616	143,134

All current tax liabilities relate to taxation of oil and gas activities and is anticipated to be settled within one year of the balance sheet date, except €47 million relating to the Solidarity Contribution Tax (note 6.4) in the Netherlands, for which the timing of settlement is uncertain.

Late or underpaid tax accrues interest at a rate of 6.25% in the UK and 10% in the Netherlands. €4 million of late payment interest was charged in the current period (2022: nil).

6.4 Uncertain tax positions

Significant judgement - recognition of Solidarity Contribution Tax provision

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 there is an argument 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 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 if it becomes payable. The Group expects to get further certainty around this tax position in 2024. A return in respect of the Solidarity Contribution Tax is required to be filed no later than 31 May 2024, along with the payment of any tax due. Should the tax authorities issue 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%.

Accounting policy

Where the Group takes positions in tax returns in which the applicable tax regulation is subject to interpretation, it considers whether it is probable that the relevant tax authority will accept that uncertain tax treatment. The Group also considers the range of potential penalties, interest or other charges that may arise from the late payment of taxes. The Group measures its tax liabilities (and related penalties, interest and other charges) based on either the most likely amount if the outcomes are binary, or the expected value if there is a range of possible outcomes.

Section 7 Other disclosures

7.1 Related party transactions

Details of transactions between the Group and other related parties are disclosed below.

7.1.1 Compensation of Directors and key management personnel

Key management personnel are considered to comprise the Directors of Kistos Holdings plc.

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Short-term employee benefits	3,092	2,607
Post-employment benefits	224	191
Total Directors' remuneration	3,316	2,798

Short-term employee benefits include €0.4 million of bonuses payable which were unpaid at year end and are included within 'Other liabilities' on the balance sheet.

In the event of a change in control of the Group, the Group is committed to pay the Executive Chairman, CEO and CFO an amount equivalent to 100% of their cash compensation received in the 12 months prior to a change of control being announced.

No long-term benefits, termination benefits or share-based payment expense was recognised in respect of the Directors. Further information regarding Directors' remuneration is provided in the Remuneration Report. The highest-paid Director had total remuneration for the period of €1.1 million (2022: €0.9 million).

7.1.2 Loans to key management personnel

€'000	Year ended 31 December 2023	Year ended 31 December 2022
At start of the period	226	238
Foreign exchange movements	5	(12)
At end of the period	231	226

Loans to key management personnel are unsecured and interest free. No expense was recognised in the current or prior period for bad and doubtful debts in respect of loans made to related parties.

7.1.3 Other related party transactions

In the current period, the Group incurred costs of €14,000 in respect of short-term rental of an aircraft owned by a member of key management personnel. The amount was outstanding at the period end. The Group also sublet a portion of its office premises to an entity wholly controlled by a member of key management personnel for nil consideration.

In the prior period, the Group paid €56,000 in rental and other property-related costs in respect of premises owned by a member of key management personnel. No amounts were outstanding at the period end.

7.2 Contingencies

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;

· 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.

All contingent payments relating to the GLA Acquisition have been either settled or derecognised (note 2.8.1).

Contingencies arising from uncertain tax positions are disclosed in note 6.4.

7.3 Assets pledged as security

As at 31 December 2023, the carrying value of financial assets pledged as security under the Group's bond debt (note 5.1) comprised €7 million of trade receivables, €14 million of inventory and €15 million of cash. In addition, the bond terms grant security over the Group's Norwegian operating assets which had a combined carrying value in the consolidated Financial Statements at 31 December 2023 of €211 million.

7.4 Auditor's remuneration

The Group (including its overseas subsidiaries) obtained the following services from the company's auditors and its associates in respect of the financial years below:

€'000	Fees for audit of the 2023 accounts	Fees for audit of the 2022 accounts
Audit fees
Audit of the consolidated Financial Statements	406	223
Audit of the Financial Statements of the subsidiaries	421	421
Total audit fees	827	644
Non-audit fees
Other assurance services	6	20
Total non-audit fees	6	20
Total	833	664

7.5 Subsequent events

There are no adjusting events subsequent to the balance sheet date. Significant non-adjusting events are outlined below.

7.5.1 Acquisition of onshore gas storage assets

On 20 February 2024, the Group agreed to acquire 100% of the issued share capital in EDF Energy (Gas Storage) Limited, which owns and operates gas storage facilities onshore in the United Kingdom, for cash consideration of £25 million, less closing working capital adjustments (the 'Gas Storage Acquisition'). The acquisition completed on 23 April 2024. There are no contingent consideration arrangements in place. The amount of acquisition-related costs to be incurred in the subsequent accounting periods is not anticipated to be material.

At the time of authorisation of these Financial Statements the Group had not completed the accounting for the Gas Storage Acquisition. Based on a preliminary assessment, the Group anticipates that substantially all of the fair value of the gross assets being acquired are concentrated in a group of similar identifiable assets, and therefore the 'concentration test' provisions of IFRS 3 'Business Combinations' can be met and the transaction will be accounted for as an asset acquisition.

Appendix A: Glossary

2C - contingent resources

2P - proved plus probable resources

Adjusted operating costs - operating costs per the income statement less accounting movements in inventory.

Average realised sales price - calculated as revenue divided by volumes sold 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

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

MMBtu - million British thermal units

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

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

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 GLA acquisition had completed on 1 January 2023, and as if the GLA Acquisition had completed on 1 January 2022. Management believe pro forma information is useful as it allows meaningful comparison of full year results across periods.

€'000	Revenue	Adjusted EBITDA
Period ended 31 December 2022:
As reported	411,512	380,015
Pro forma period adjustments	156,933	137,187
Pro forma	568,445	517,202

Period ended 31 December 2023:
As reported	206,997	120,777
Pro forma period adjustments	16,095	1,542
Pro forma	223,092	122,319

B2 Net debt

Net debt is a measure which management believe is useful as it provides an indicator of the Group's overall liquidity. It is defined as 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	31 December 2023	31 December 2022
Cash and cash equivalents	4.1	194,598	211,980
Face value of bond debt (excluding Hybrid Bond)	5.1	(218,917)	(81,572)
Net (debt)/cash		(24,319)	130,408

B3 Adjusted operating costs and unit opex

Adjusted operating costs are operating costs per the income statement less accounting movements in inventory, which are primarily those operating costs capitalised into liquids inventory as produced and expensed to the income statement only when the related product is sold.

€'000	Year ended 31 December 2023	Year ended 31 December 2022
Production costs	72,888	22,927
Accounting movements in inventory	(1,048)	4,135
Adjusted operating costs	71,840	27,062
Pro forma period adjustment	10,221	19.706
Pro forma adjusted operating costs	82,061	46,768


Total production (kboe)	2,995	2,732
Pro forma period adjustment (kboe)	226	1,230
Total pro forma production (kboe)	3,221	3,962

Unit opex	€24/boe	€10/boe
Pro forma unit opex	€25/boe	€12/boe

Appendix C Conversion Factors

The conversion factors below have been used by management in the presentation of certain disclosures in the Annual Report on a consistent basis.

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

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: Welligence Energy Analytics.

[2] Pro forma figures for 2023 include Kistos Norway as if it had been acquired on 1 January 2023. The acquisition completed on 23 May 2023. Pro forma figures for 2022 include GLA as if it had been acquired on 1 January 2022. The acquisition completed on 10 July 2022. Minor adjustments have been made to comparative pro forma information following receipt of additional information after completion of the GLA acquisition and to align with the Group's accounting policies and methodology as used in the 2022 Annual Report and Accounts.

[3] Non-IFRS measure (refer to definition within the glossary). Sales volumes are converted to estimated boe using the conversion factors in Appendix C to the Financial Statements.

[4] Non-IFRS measure (refer to definition within the glossary and reconciliation in Note 2.2.2, Appendix B2 and Appendix B3 to the Financial Statements).

[5] Non-IFRS measure (refer to definition in the glossary and Appendix B3 to the Financial Statements).

[6] Pro forma figures for 2023 include Kistos Norway as if it had been acquired on 1 January 2023. The acquisition completed on 23 May 2023. Pro forma figures for 2022 include GLA as if it had been acquired on 1 January 2022. Adjusted EBITDA by region is reconciled to total Adjusted EBITDA in note 2.2.2 to the Financial Statements. Pro forma information is reconciled to actual results in Appendix B2 to the Financial Statements.

[7] Operated sites and projects comprise oil and gas fields, facilities and infrastructure where the Group has control, responsibility and accountability over activities, safety, emissions and decisions impacting the sites. Operated sites therefore comprise all Dutch licences, including the Q10-A platform, and offices owned or leased by the Group.

[8] Source: North Sea Transition Authority.

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