Kistos Holdings Regulatory News (KIST)

13th May 2024

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

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

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

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

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.

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

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.

Consolidated Financial Statements

Consolidated income statement

Consolidated statement of other comprehensive income

Consolidated balance sheet

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

Consolidated cash flow statement

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

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.

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:

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

2.1 Revenue

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.

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

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

2.3 Abandonment provision

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

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

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

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 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. Costs of disposal were considered to be immaterial for the purposes of the impairment test.

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 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. Costs of disposal were considered to be immaterial for the purposes of the impairment test.

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 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 €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

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.

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

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:

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:

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:

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:

Section 3 Income statement

3.1 Earnings per share

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

3.3 Employee benefit expenses 

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:

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