30 May 2023

 

 

Kistos Holdings plc

 

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

 

Full-year results for the year ended 31 December 2022

 

 

Kistos (LSE: KIST), the low carbon intensity gas producer pursuing energy 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 2022. 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.

 

 

2022 Highlights

 

·    On a pro forma basis, the Group production averaged 10.6 kboe/d (2021: 4.3 kboe/d), reflecting a full-year contribution from the Q10-A gas field offshore the Netherlands, and almost six months production from the Greater Laggan Area ("GLA") offshore the UK.

·    Adjusted pro forma EBITDA, which includes a full 12-month contribution from the GLA, was €517.2 million (2021: €102.9 million).

·    Completed the acquisition of a 20% interest from TotalEnergies E&P UK Limited ("TotalEnergies") in the GLA, more than doubling Kistos' net daily production.

·    Year-end 2P reserves of 12.7 MMboe increased to 36.3 MMboe on completion of the Mime Petroleum A.S. ("Mime") transaction.

 

 

12 months ended 31 December 2022

		2022 (actual)	2022 (pro forma)1	2021 (actual)	2021 (pro forma)1
Gas production2	MM Nm3	391	556	145	268
Total production rate3	Boe/d	10,600	10,900	4,300	5,000
Revenue	€'000	411,512	568,445	89,628	116,731
Average realised gas price2	€/MWh	98.7	93.8	57.4	39.8
Unit opex4	€/MWh	5.8	6.9	3.7	3.2
Adjusted EBITDA4	€'000	380,015	517,202	78,861	102,862
Statutory profit/(loss) before tax	€'000	254,125	n/a5	(73,857)	(65,940)
Effective tax rate	%	89.8%	n/a5	45.7%	n/a5
Closing cash	€'000	211,980	211,980	77,288	77,288

1.         Pro forma figures include the GLA as if it had been acquired on 1 January 2022. The acquisition completed on 10 July 2022. Pro forma figures for 2021 include the results of Kistos NL1 and Kistos NL2 as if they had been acquired on 1 January 2021.

2.         Comparative information has been restated to align with current year allocation methodology.

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

4.         Non-GAAP measure. Refer to Appendix B to the financial statements for definition and calculation.

5.         Certain pro forma equivalents are not applicable or meaningful. The GLA acquisition comprised the purchase of interests in an unincorporated joint arrangement with no pre-existing IFRS income statement, balance sheet or cash flow statement from which to derive pro forma information.

 

 

Financial

Strong cash generation in both halves of the year, with movements in gas prices and production rates offsetting each other

 

·    Profit after tax of €73 million, including €44 million of impairment charges relating to exploration assets in the Netherlands, €27 million of gains from changes and releases in acquisition contingent consideration balances, and a total tax charge of €228 million.

·    The tax charge (resulting in an effective tax rate for 2022 of 89.8%) includes impact of the Energy Profits Levy in the UK and the EU Solidarity Contribution Tax in the Netherlands.

·    Cash balances on 31 December 2022 of €212 million (31 December 2021: €77 million) and net cash of €130 million (31 December 2021: net debt of €73 million).

·    Retired 46% of outstanding debt by repurchasing €68 million of Nordic Bonds, leaving €82 million outstanding.

·    Capital expenditure on a cash basis, excluding business acquisitions, was €19.5 million.

 

 

Operational

Increasing the Group's production base with organic and inorganic growth

 

·    Year-end 2P reserves of 12.7 MMboe increased to 36.3 MMboe on completion of the Mime Petroleum A.S. (Mime) transaction.

·    Drilling of the Benriach exploration well (Kistos 25%) approved and was spudded in March 2023.

·    Estimated Scope 1 CO₂ emissions from our operated activities offshore were less than 0.01 kg/boe in 2022 (excluding necessary flaring during drilling campaigns)

 

 

Outlook

Transforming Kistos into an influential independent North Sea E&P across three proven energy markets

 

·    Mime acquisition completed in May 2023, adding 2P reserves of 23.6 mmboe and 2,000 boe/d of production in 2023, increasing to over 15,000 boe/d in 2025 once the Jotun FPSO is onstream.

·    The Mime acquisition provides a platform for growth on the Norwegian Continental Shelf

·    Kistos is ready to sanction the Edradour West and Glendronach developments in the GLA (subject to JV partner approval), utilising investment allowance under the terms of the UK Energy Profits Levy. If approved, Edradour West development programme anticipated to commence by year-end 2023.

 

 

Andrew Austin, Executive Chairman of Kistos, commented:

 

"Kistos' accelerated evolution over the course of 2022 has been driven by targeted value-accretive acquisitions which have provided both immediate and longer-term upside for the Group. Our entry into the UKCS, followed this year by Norway, has created a diversified and flexible portfolio across multiple jurisdictions.

 

The Group benefited from strong commodity prices resulting in significant cash generation, which will allow us to continue to capitalise on the exploration, appraisal, and development opportunities within our portfolio. However, these strong commodity prices have resulted in authorities imposing so-called windfall taxes on our operations. This is difficult to comprehend, given that greenhouse gas emissions associated with imported hydrocarbons are typically much higher than those associated with those produced locally. This tax instability has already resulted in Kistos and companies with international asset portfolios cancelling or scaling back North Sea projects and diverting capital elsewhere, with significant implications for local energy security of supply.

 

In particular, the imposition of the retrospective and regressive Solidarity Contribution Tax on our Netherlands profits means that the Group, and other energy industry participants in the EU, will find it difficult to justify future material investments and developments due to the risk of confiscation of profits should oil or gas prices rise again. We believe our Dutch subsidiary is out of scope of the charge, but have nonetheless made a provision for it in these results, pending further clarification and the outcome of legal challenges from other parties.

 

From a standing start in 2020, we have built an excellent platform, and we will seek to deploy further capital in the right opportunities or make distributions to shareholders. The instability of the fiscal regimes in which we operate has prompted us to review our investment options and, as we have already demonstrated with our entry into Norway, our pipeline of business development opportunities includes assets in jurisdictions other than the UK and the Netherlands in which we can continue to generate substantial returns for investors."

 

 

 

Enquiries

 

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

 

Notes to editors

 

Kistos Holdings plc was established to acquire and manage companies in the energy sector engaging in the energy transition trend. The Company has undertaken a series of transactions including the acquisition of a portfolio of highly cash generative natural gas production assets in the Netherlands from Tulip Oil Netherlands B.V. in 2021. This was followed in July 2022, with the acquisition of a 20% interest in the Greater Laggan Area (GLA) from TotalEnergies, which includes four producing gas fields and a development project. In May 2023 Kistos completed the acquisition of Mime Petroleum A.S. adding 24 MMboe of 2P reserves and significant production.

 

Kistos is a low carbon intensity gas producer with Estimated Scope 1 CO2 emissions from our operated activities offshore of less than 0.01 kg/boe in 2022 (excluding necessary flaring during drilling campaigns).

 

 

Executive Chairman's Statement

 

After completing its first acquisition in May 2021, Kistos has built on that platform in 2022 with the acquisition of a 20% working interest in the GLA from TotalEnergies.

Located offshore of the UK, west of Shetland, the GLA acquisition approximately doubled our production when it completed in July 2022. With natural gas representing c.90% of GLA output, the deal was consistent with our ambition to build a portfolio of assets with a role to play in the energy transition. Development and exploration upside was also added to the portfolio.

In the 12 months to the end of December 2022, net production from Q10-A gas field offshore the Netherlands (Kistos 60% and operator) averaged 4,700 boe per day (2021: 5,000 boe per day pro forma). The drilling programme we commenced in July 2021 -  shortly after taking control of the asset which was completed in February 2022 - achieved its aim of minimising the natural decline in production; although the appraisal well drilled on the Q11-B gas discovery failed to encounter gas in the primary Slochteren target (but did successfully test gas from the Bunter and Zechstein formations).

A further drilling campaign at Q10-A was initiated in November 2022 and departed in March 2023 having safely completed its work programme. The Kistos technical team, with the assistance of external consultants, is undertaking a detailed evaluation of the campaign results and future production enhancement options, and we are evaluating the potential for further drilling campaigns in the future. This is being done with a view to accelerating production and maximising recovery from Q10-A, especially now the decision has been taken to continue utilising the P15-D platform for export.

This was announced alongside our interim results in September 2022. As we stated then, it substantially reduces future capital expenditure and eliminates the risk of production interruptions resulting from the work to install a new export route. In addition, changes to the tax environment have made investment less attractive. For those reasons, it was the right decision economically. However, because Q10-A will remain reliant on the availability of older infrastructure that we don't control, cessation of production is likely to occur in the 2030s rather than the 2040s. This was a major contributor to the reduction in Group proved and probable reserves in 2022.

Production from GLA in 2022 averaged 5,900 boe per day from acquisition (6,200 boe per day net to Kistos on a pro forma basis). This was in line with expectations, with onshore processing at the Shetland Gas Plant (SGP) allowing for very reliable operations. On a pro-forma basis, the acquisition contributed €250 million of Adjusted EBITDA in 2022. The headline cost of acquiring these assets was US$125 million, based on an effective economic date of 1 January 2022. The final firm cash consideration payment was US$43 million, the difference being the post-tax cashflows generated from the assets between the effective economic date and the completion date of 10 July 2022.

Having completed three acquisitions to date, we remain focused on building the business and we continue to evaluate a pipeline of business development opportunities, which includes geographies other than the Netherlands and the UK. Nevertheless, if we are to add value for shareholders, it is critical that we maintain our financial discipline and avoid overpaying for assets. Hence, the Board will consider making cash distributions to shareholders if attractive opportunities cannot be identified. It is in this context we decided not to pursue a proposed combination with Serica Energy last summer. While both the Kistos and Serica Boards agreed on the strong industrial logic of a combination, terms could not be agreed that the Board believed fully reflected the value of Kistos.

Importantly, while we assess other potential acquisitions, we are pursuing the organic growth opportunities within our existing portfolio. During 2022, the Orion oil field development project completed the Concept Assess phase and moved into the Concept Select phase and we expect to submit a Field Development Plan (FDP) and permitting requests to the authorities before the end of this year. In addition, we remain mindful of the opportunity to develop the Q11-B gas discovery but at present work is on hold due to the uncertainty surrounding the tax regimes in the Netherlands. This has caused us to fully impair the value of the assets until such time as there is sufficient fiscal clarity or incentives available to encourage investment in energy security.

In the UK, the Board of Directors has approved Kistos' participation in the Benriach exploration well, (Kistos 25%) west of Shetland. The well was spudded in March 2023, targeting 638 Bcf (operator's gross P50 resource estimate) with results expected in mid-2023. The Board is also ready to sanction the Edradour West and Glendronach developments in the GLA, west of Shetland, with a decision by the joint-venture partners as to the order and timing of developments expected to be taken later in 2023 to allow further technical reviews to be undertaken with the aim of reducing costs.

Central to our operations is our health, safety and environmental (HSE) performance. While our overall performance was positive, we did suffer one lost time incident in early 2022 on the Borr drilling rig, but we did not suffer any medical treatment cases and there was no increase in first aid cases. This was despite having drilling rigs on location for more than six months of the year.

Following an upgrade of the wind turbines in 2021, the renewably powered Q10-A platform maintained its excellent emissions intensity track record during 2022 with Scope 1 CO₂ emissions of less than 0.01 kg per boe (excluding necessary flaring during drilling campaigns). CO₂ emissions from GLA during the period remained below the average for the UK North Sea at 11.9 kg per boe (Scope 1 and Scope 2) and substantially below the level attributable to imported liquefied natural gas (LNG).

Given that the greenhouse gas emissions associated with imported hydrocarbons are typically much higher than those associated with locally produced hydrocarbons, the imposition of so-called windfall taxes on Europe's upstream oil and gas industry is difficult to comprehend. This is all the more so when the negative implications of these measures for energy security of supply are also considered. We have already seen companies with international asset portfolios cancelling North Sea projects and diverting capital overseas, and the instability of the fiscal regimes in which we operate has prompted us to review our investment options.

We are particularly disappointed by the Dutch authorities' retrospective implementation of the EU's Solidarity Contribution Tax, which imposes an additional 33% charge on so-called 'surplus profit' made in 2022. Surplus profit is defined as anything more than 120% of a company's average annual profit from 2018-2021 inclusive. Firstly, and by their very nature, retrospective taxes go against the long-standing consensus that one of the key characteristics of a taxation system is that it should have a principle of certainty. Secondly, on a company level, the Solidarity Contribution Tax unfairly impacts companies such as Kistos, that had hedged some or all their 2022 gas sales below spot prices, whereas the counterparties that enjoyed profits on the other side of these hedges have not been subjected to the tax. Finally, the mechanism by which the tax is calculated, by reference to so-called 'baseline' profits for the years 2018 to 2021 inclusive, covers some of the lowest commodity prices in the last decade and, in the case of Kistos, years in which the Group's Dutch subsidiary realised losses or minimal profits due to it being in a pre-production phase.

The imposition of this regressive tax means that the Group, and the other energy industry participants in the EU, will find it difficult to justify future material investments and developments due to the risk of confiscation of profits should oil or gas prices rise again. As in the case of Kistos, this has had an immediate effect on investment being allocated to the Netherlands, such as not proceeding with the reroute of production from Q10-A, which in turn affects our 2P reserve base. We understand the implementation of the Solidarity Contribution Tax is subject to legal challenges by other parties, and, separately, we believe there is an argument that our Dutch subsidiary is out of scope of the charge. This is because the Board of Directors is of the opinion that under DAS 270 of Dutch GAAP (the relevant accounting standard), the revenue threshold for Kistos NL2 to be liable for the Solidarity Contribution has not been met. However, as there is no history or precedent for this tax being audited or collected by the Dutch tax authorities, the Group has applied IFRIC 23, 'Uncertainty over Income Tax Treatments' and recorded a liability of €46.9 million relating to the Solidarity Contribution Tax in the current tax charge for the year.

Alongside several of our counterparties in the sector, we are lobbying the UK and Dutch Governments to address our concerns and take action that will save jobs, reduce carbon emissions, reduce the balance of payments deficit and minimise dependence on energy imports. We hope they will listen and act accordingly, but we cannot be certain of that. Therefore, as stated earlier, our focus has to be elsewhere, and our pipeline of business development opportunities now includes assets in jurisdictions other than the UK and the Netherlands.

To that effect, in April 2023 we announced that we had reached a conditional agreement to acquire Mime Petroleum A.S. (Mime). The transaction completed in May, and marks our entry into the Norwegian Continental Shelf (NCS), adding 24 MMboe of 2P reserves plus 30 MMboe of 2C resources, primarily oil. In terms of production, Mime will add over 2,000 boe/d immediately and help to boost Group output to in excess of 15,000 boe/d in 2025 once the Jotun FPSO (on the Balder X development) is onstream. The transaction will also act as a platform for growth for Kistos and Mime in Norway.

Adjusted EBITDA for 2022 was €380.0 million (2021: €78.9 million) while adjusted pro forma EBITDA, which includes a full 12-month contribution from the GLA, was €517.2 million (2021: €102.9 million). This was split evenly between the first half and the second half of the year, with movements in gas prices and production rates offsetting each other. Hence, we ended the year with net cash of €130.4 million (2021: net debt of €72.7 million), which was achieved after paying for the GLA acquisition and cash capital expenditure of €19.5 million (2021: €20.0 million).

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. From a standing start in the fourth quarter of 2020, we have built an excellent platform and we will seek to deploy further capital in the right opportunities or make distributions to shareholders. Although we do not set explicit long-term targets for reserves or production, our focus for which we are well-placed is to continue generating substantial returns for investors and look forward to reporting further progress during 2023.

 

Operating Review

 

2022 was an important year for Kistos, as our acquisition of a 20% interest in the GLA consolidated our position as an operating business with significant reserves, production and technical expertise.

Our Dutch assets contributed a full 12 months of production to the Group for the first time and the pro forma Group average gas production rate was 1.52 million Nm³ per day (net to Kistos) compared with 0.73 million Nm³ per day on a pro forma basis in 2021. Average daily production was higher in the first half of the year owing to a planned maintenance shutdown on the P15-D platform in the third quarter of the year.

On 31 January 2022, Kistos entered into an agreement with TotalEnergies to acquire assets including:

·    20% working interests in the producing Laggan, Tormore, Edradour and Glenlivet
gas fields, located offshore the UK, west of Shetland.

·    20% interest in the undeveloped Glendronach gas field.

·    25% interest in block 206/4a, which contains the 638 Bcf (operator's gross P50 resource estimate) Benriach prospect.

·    20% interest in the SGP.

The consideration payable in respect of the acquisition comprised initial cash consideration of US$125 million (at the effective economic date of 1 January 2022) plus certain contingent payments. These payments relate to the average day-ahead gas price at the National Balancing Point in 2022 and to the potential development of Benriach.

Kistos expected production from the GLA to approximately double Group output. In the event, it exceeded that expectation and, on a pro forma basis, delivered an average of 0.83 Nm³ per day net to Kistos, which represented 54% of the Group total. Uptime in 2022 was excellent, at over 95% excluding planned maintenance.

Drilling campaigns

During 2022, we were engaged in two drilling campaigns. The first commenced with the arrival of Borr Drilling's Prospector-1 jack-up drilling rig at the Q10-A field in mid-July 2021. It continued until February 2022. The outcome of this programme was:

·    A flow test of the Q10-A Orion oil discovery.

·    A sidetrack of the Q10-A-04 well, which was not producing, to a new location in the Slochteren formation.

·    A series of production-enhancing workovers on existing producing wells at the Q10-A gas field.

·    An appraisal well on the Q11-B gas discovery (which flowed gas from the Bunter and Zechstein formations, although failed to encounter gas in the primary Slochteren target)

The second campaign commenced in October 2022 with the arrival at Q10-A of the Valaris 123 jack-up drilling rig. This ended in March 2023 and focused on mitigating recovery from Q10-A by accelerating the recovery of hydrocarbons from certain reservoirs and improving the stability of other producing wells.

An important part of the acquisition in the Netherlands in 2021 was gaining access to a highly skilled workforce and an operating capability. It is a tribute to the team that we had only one Lost Time Incident in more than nine months of drilling and testing across two separate campaigns.

Gas producing assets

Q10-A (Kistos 60% and operator)

From May 2021 to July 2022, Q10-A was Kistos' principal producing asset. It straddles the Q07 and Q10-A production licences approximately 20 km offshore the Netherlands and received development approval in January 2018. Little more than a year after the project was sanctioned, commercial gas production was achieved in February 2019.

The facilities comprise a remotely operated, unmanned platform with six well-slots, located in relatively shallow water of approximately 21 metres. The platform was designed to have as small a carbon footprint as possible, with on-board wind turbines and solar panels providing most of its power. Furthermore, any visits to the platform are carried out by boat rather than by helicopter.

We estimate the Scope 1 emissions related to our production activities offshore the Netherlands were less than 0.01 kg CO₂e/boe in 2021 and 2022. Produced gas is exported through a dedicated 42 km pipeline to the TAQA-operated P15-D platform, where it is processed for onward transportation to shore. Following a thorough review in 2022 of potential alternative export routes, and in light of recent tax changes, a decision was taken to continue using P15-D. This reduces future capital expenditure and removes the risk of interruptions to production caused by the project. However, Q10-A's continued reliance on P15-D means it is now likely to cease production in the early 2030s rather than in the 2040s.

Greater Laggan Area (Kistos 20%)

The producing Greater Laggan Area (GLA) gas fields are in water depths of approximately 300 to 625 metres and are located up to 125 km north-west of the Shetland Islands. Development approval was originally granted in 2010 and first gas was achieved at the Laggan and Tormore fields during 2016. The Glenlivet and Edradour fields received development approval in 2015 and subsequently came on-stream in 2017.

The fields are tied back to the onshore SGP by a 140-kilometre pipeline network, which represents the longest subsea-to-shore system in the UK North Sea. The SGP is located on the north coast of the main island of the Shetland Islands. When the hydrocarbons arrive onshore, the liquids (condensates) are removed and piped to the nearby Sullom Voe Terminal, while the gas is processed at SGP before being exported to the St Fergus Gas Terminal in Scotland.

In 2022, the CO₂ emissions intensity from GLA production (on a Scope 1 and Scope 2 basis) was approximately 12 kg per boe, well below the UK average for offshore gas fields of 22 kg per boe. As production from the GLA naturally declines (prior to any incremental production coming on stream) this intensity ratio is anticipated to increase in 2023. The joint venture operator is evaluating energy efficiency and electrification options at the SGP during 2023 to further reduce the asset's carbon intensity.

Development projects

Netherlands: Q10-A Orion (Kistos 60% and operator)

Kistos drilled an appraisal well at the Q10-A Orion oil field in 2021 and successfully flow tested an 825-metre horizontal section of the reservoir at a rate of 3,200 b/d. The result led to a decision to commence the Concept Assess phase of development planning for the field. This involved building new static and dynamic reservoir models before evaluating several development concepts with a view to creating a shortlist of options to take forward into a more detailed phase of work.

Concept Assess was successfully completed in the second half of 2022. This led to three development concepts being taken forward to the Concept Select phase of the project, which commenced in early 2023. This is expected to be completed later in 2023, potentially enabling a Final Investment Decision (FID) to be taken by the end of the year.

Netherlands: Q11-B (Kistos 60% and operator)

The Q11-B appraisal well was suspended in February 2022. Although it failed to produce gas from its primary target, this disappointment was tempered by successful tests from the Zechstein and Bunter formations. These outcomes, combined with adverse changes to the Dutch fiscal regime, have meant that there is currently no material expenditure on these licences budgeted or planned, and as such the amounts relating to Q11-B have been fully impaired.

GLA: Glendronach (Kistos 20%)

The Glendronach field was discovered in 2018 and is part of the GLA. It is anticipated that the field will be developed with a single well tied back to existing infrastructure. It is expected to extend the life of the GLA, but FID was deferred by the joint-venture partner in the second half of 2022. It is now undertaking further technical reviews with the aim of reducing the cost of the project and Kistos anticipates FID will be taken in the second half of 2023.

Exploration

GLA: Benriach (Kistos 25%)

Drilling of the Benriach exploration prospect, operated by our partner TotalEnergies, commenced at the end of Q1 2023 and is targeting an operator-estimated P50 gross recoverable resources of 638 Bcf (110 Mmboe), being 160 Bcf (28 Mmboe) net to Kistos. Kistos' share of the cost of the well on a dry-hole basis is forecast to be c.€18 million pre-tax or c.€3 million post tax.

Other

UK 33^rd Round (Kistos 25%)

Kistos is part of a TotalEnergies-led joint venture that has re-applied for six blocks or part-blocks in the GLA as part of the UK Government's 33rd Offshore Oil and Gas Licensing Round. The acreage covers 24km² and includes the Ballechin exploration prospect.

M10/M11 and other NL licences (Kistos 60%)

During the first half of 2022, Kistos applied for the M10a and M11 (Kistos 60%) licences north of the Wadden Islands to be extended beyond 30 June 2022. Historically, Kistos has had licences extended past their expiry date but, on this occasion and in common with some other operators with similar licences, the Company was informed that the extension had not been granted by the Dutch authorities.

Kistos subsequently engaged in discussions with the Dutch authorities and lodged an appeal against this decision. This included full details of our rationale for doing so plus a draft FDP to which the Board of Directors is willing to commit capital. We are awaiting the outcome of the appeal, which was heard in December 2022. As a result of this, the balance relating to M10/M11 of €7.5 million has been impaired in full, although this was offset by a release of contingent consideration payable of the same amount.

Outside of the M10/M11 area, in January 2023 Kistos was awarded the P12b, Q13b and Q14 licences covering a total acreage of 507 km² adjacent to the existing Q10 block.

Reserves

Kistos exited 2021 with 2P reserves of 18.1 Mmboe in the Netherlands while our 20% interest in the GLA contained a further 6.2 Mmboe at the same date. Since then, our reserves have been impacted by the economic implications of fiscal changes in the UK and the Netherlands. Therefore, while there has been some reduction in technical reserves due to reservoir performance, economic reserves have been materially impacted.

Pro forma production in 2022 was 4.0 Mmboe while the decision to continue exporting via P15-D, for the reasons stated above, reduced reserves by a further 4.3 Mmboe. This is because it is expected to result in Q10-A ceasing production earlier than under an alternative export route, due to limitations on the existing infrastructure. Net downward revisions to previous reserves estimates, which relate primarily to the Q10-A reservoir proving to be tighter than originally thought, amounted to 3.3 Mmboe. Overall, these movements led to Kistos ending 2022 with 2P reserves of 12.7 Mmboe.

Acquisition of Mime

After the period end, in April 2023 Kistos entered into an agreement to acquire 100% of the share capital of Mime Petroleum A.S (Mime), and completed the transaction on 22 May 2023. The consideration for the transaction is US$1 plus the issue of up to 6 million warrants exercisable into new Kistos ordinary shares at a price of 385p each. 3.6 million of the warrants can be exercised between completion of the transaction and 18 April 2028. The balance will be exercisable from 1 June 2025 until 18 April 2028. A payment to Mime's bondholders of up to US$45MM in 2025 is contingent on certain operational milestones being achieved.

Overview of Mime

Mime is headquartered in Oslo, Norway. It has an experienced management team and is focussed on development and production projects on the Norwegian Continental Shelf (NCS). It holds a 10% interest in the Balder joint venture (comprising the Balder and Ringhorne fields) and a 7.4% stake in the Ringhorne East unit, all operated by Vår Energi A.S.A.

Based on operator estimates, 2P reserves at Balder and Ringhorne were 23.6 Mmboe net to Mime at the end of 2022. In addition, Kistos estimates Mime has net 2C resources of 29.8 Mmboe, largely comprised of additional upside in Balder and Ringhorne plus the 2021 King oil discovery

Mime's share of production from Balder and Ringhorne is expected to be over 2,000 boe/d in 2023. This will increase significantly once the Balder X project is onstream, with production for the enlarged Group expected to be over 15,000 boe/d in 2025 once the Jotun Floating Production Storage and Offloading vessel (FPSO) is onstream.

Balder X comprises the Balder Future and Ringhorne Phase IV drilling projects and is designed to extend the life of the Balder Hub. It includes upgrading the Jotun FPSO, which is more than 70% complete and is forecast by the operator to sail away in 2024.

Scope 1 and Scope 2 CO₂ emissions from the Balder Hub are expected to fall by more than 50% to approximately 7.5kg per boe once Balder X is onstream. This is well below both the global and the North Sea average.

Acquisition terms and consideration

Following completion and restructuring of Mime's existing bonds, the additional debt assumed by the Group will total $225 million, comprising:

·    $120 million of Super Senior bonds, which will attract interest of 9.75% per annum, 4.50% of which is payable in cash and 5.25% of which is payable-in-kind in the form of additional Super Senior bonds. The maturity date of the Super Senior bonds is 17 September 2026.

·    $105 million of so-called "MIME02" bonds, which will attract an interest rate of 10.25% payable-in-kind. The maturity date of the MIME02 bonds is 10 November 2027.

A contingent payment of $45 million will be made to the MIME02 bondholders in the event 500,000 bbl (gross) have been offloaded and sold from the Jotun FPSO by 31 December 2024. This will decline to $30 million from 1 January 2025 to 28th February 2025, to $15 million from 1 March 2025 to 31 May 2025, and to zero thereafter.

If 500,000 bbl (gross) has not been offloaded and sold from the Jotun FPSO by 31 May 2025, the holders of Mime's Nordic Bonds will be allocated up to 2.4 million warrants exercisable into Kistos ordinary shares at a price of 385p each. The warrants can be exercised between 30 June 2025 and 18 April 2028. Simultaneously, up to 1.9 million of the 5.5 million warrants issued as consideration for the Mime shares will be cancelled.

Financial Review

 

		31 December 2022 (actual)	31 December 2022 (pro forma)1	31 December 2021 (actual)	31 December 2021 (pro forma)1
Revenue	€'000	411,512	568,445	89,628	116,731
Average realised gas price	€/MWh	98.7	93.8	57.4	39.8
Unit opex2	€/MWh	5.8	6.9	3.7	3.2
Adjusted EBITDA2	€'000	380,015	517,202	78,861	102,862
Profit before tax	€'000	254,125	n/a3	(73,857)	(65,940)
Earnings/(loss) per share	€	0.31	n/a3	(0.68)	n/a3
Operating cashflow	€'000	290,473	n/a3	47,956	n/a3
Cash capital expenditure	€'000	19,454	n/a3	19,958	n/a3
Closing cash	€'000	211,980	211,980	77,288	77,288

 

1. Pro forma figures include the GLA as if it had been acquired on 1 January 2022. The acquisition completed on 10 July 2022. Pro forma figures for 2021 Include the results of Kistos NL1 and Kistos NL2 as If they had been acquired on 1 January 2021.

2. Non-IFRS measure. Refer to Appendix B to the financial statements for definition and calculation.

3. Certain pro forma equivalents not applicable. The GLA acquisition comprised the purchase of Interests In an unincorporated joint arrangement with no pre-existing IFRS Income statement, balance sheet or cash flow statement from which to derive pro forma Information

Production and revenue

Gas production on a working interest basis totalled 391 million Nm³ (10.6 kboe/d total hydrocarbon production) in the year to 31 December 2022 (2021: 145 million Nm³ gas production, and 4.3 kboe/d total hydrocarbon production). This 270% increase reflected a full year contribution from the Q10-A, versus seven months in 2021, and almost six months production from our interest in the GLA. On a pro forma basis, Kistos gas production significantly increased in 2022 from 268 million Nm³ (5.0 kboe/d total hydrocarbon production) to 556 million Nm³ or (10.9 kboe/d total hydrocarbon production).

The Group's average realised gas price during the period was €98.7/MWh versus €57.4/MWh in 2021 and this, combined with higher production, resulted in total revenue from gas sales increasing by 459% year-on-year to €411.5 million. This includes the impact of the hedging programme in the Netherlands which ended in March 2022, whereby 300,000 MWh was hedged at €25/MWh. On a pro forma basis, these figures were €93.8/MWh and €568.4 million. Revenue from natural gas liquids (NGL) and crude oil sales was €nil but €10.7 million on a pro forma basis, reflecting the timing of liftings in the periods. This compared with €0.1 million and €0.6 million on a pro forma basis in 2021.

Costs

GLA inevitably costs more to operate than Q10-A, with the fields lying in much deeper water, further from shore and a much greater distance to the market. Hence, unit opex costs for the period on a consolidated level increased from €3.7 per MWh in 2021 to €5.8 per MWh in 2022. On a pro forma basis, there was a more pronounced increase from €3.2 per MWh in 2021 to €6.9 per MWh in 2022 reflecting a full year of higher GLA operating costs.

During 2022, Kistos incurred pre‑FID development expenses of €1.8 million (2021, €4.5 million) on potential alternative evacuation routes for the Q10-A platform in addition to progressing development on Orion. As FID was not taken on the alternative evacuation routes, and Orion is still subject to FID, these costs have been expensed in the profit and loss account. Following the decision to continue exporting Q10-A gas via the P15-D platform, no further expenditure is anticipated in 2023.

 

Adjusted EBITDA

€'000	Year ended 31 December 2022	Period ended 31 December 2021
Pro forma1 Adjusted EBITDA	517,202	102,862
Pro forma1 adjustment	(137,187)	(24,001)
Adjusted EBITDA	380,015	78,861
Depreciation and amortisation	(83,234)	(13,277)
Impairments	(44,547)	(121,036)
Development expenses	(1,752)	(4,456)
Transaction costs	(681)	(2,864)
Share-based payments	(538)	-
Contingent consideration movements	26,993	-
Operating profit/(loss)	276,256	(62,772)

 

1.                     Pro forma figures include results from GLA as if it had been acquired on 1 January 2022, and, for 2021, as if the Tulip Oil acquisition had completed on 1 January 2021. The acquisitions completed on 10 July 2022 and 20 May 2021 respectively.

 

Adjusted EBITDA was €380.0 million or €81.9 per MWh equivalent of production in 2022. Both figures were substantially ahead of the comparable figures for the period to 31 December 2021 of €78.9 million and €47.5 per MWh equivalent respectively, primarily driven by the material increase in commodity prices during the period. On a pro forma basis, Adjusted EBITDA was €517.2 million or €76.7 per MWh equivalent of production versus €102.9 million or €33.4 per MWh equivalent in 2021.

The impairments primarily relate to the Q11-B and Q10-B assets (€36.8 million), which have been impacted by changes to the fiscal regime introduced by the Dutch tax authorities during 2022. These have introduced uncertainty into what was previously a stable and predictable fiscal regime and, unlike equivalent measures in the UK, do not incentivise licence holders to invest further by means of enhanced deductions for investment capital expenditure. Pending further clarity on these measures and whether they are to be extended, there is currently no substantive expenditure on these licences budgeted or planned. As such, there is no longer sufficient certainty over whether the carrying value can be recovered from future development the amounts relating to Q11-B have been fully impaired.

Additionally, a charge of €7.5 million was recognised against the M10/M11 licences. This has been impaired because, as at the balance sheet date, the Group's application to renew the relevant licence had not been approved and there is uncertainty as to whether the Group would be successful in its appeal and/or re-application. As the Group no longer holds the licences, the contingent consideration payable to seller, which would have crystallised upon taking forward further development, has been derecognised resulting in an offsetting €7.5 million gain.

Capital expenditure

Consistent with our growth plans and to ensure we maximise the value of our asset portfolio, capital expenditure in 2022 was €19.5 million (2021 €20.0 million) on a cash basis. The majority of this related to our two drilling campaigns. With FID for Glendronach delayed, and Orion still in the Concept Select phase, capital expenditure in 2023 will not ramp up as much as we originally expected. Out of currently anticipated cash spend of €40-45 million, approximately three-quarters relates to the Dutch drilling campaign that completed in March 2023 or to the pre-tax costs of the Benriach exploration well. On a post-tax basis, we expect the Benriach costs to be c.15% of the pre-tax costs, as a result of the interaction between capital expenditure and the EPL. Kistos expects Mime's capital expenditure for the full year 2023 to be up to $130 million. Tax relief is available on this expenditure at a rate of 78% and is expected to result in a cash tax refund in December 2024.

Profit/loss before tax

Operating profit for the period was €276.3 million (2021: operating loss of €62.8 million) and a profit before tax of €254.1 million (2021: loss before tax of €73.9 million). This figure was after impairments of €44.5 million (2021: €121.0 million), and net finance costs of €22.1 million (2021: €11.1 million), including interest charges of €10.5 million associated with Kistos NL2's Nordic Bonds and a non-cash  loss on redemption of €6.4 million relating to repurchases of €68.4 million of Nordic Bonds during the period (arising as the bonds were repurchased at a small premium to par).

Balance sheet

At the end of 2022, the Group held cash and cash equivalents of €212.0 million (31 December 2021, €77.3 million) and net cash of €130.4 million (31 December 2021, net debt of €72.7 million). The increase in net cash of over €200 million was achieved after capital expenditure and acquisition cash outflows of €67.0 million and bond repurchases of €71.8 million, and reflected a 605% increase year-on-year in operating cash flow from €48.0 million to €290.5 million.

Taxation

The effective tax rate for the Group in 2022 was 89.8% (2021: 45.7%). The increase was driven by the introduction, and subsequent increase and extension, of the Energy Profits Levy in the UK and the imposition of the Solidarity Contribution Tax in the Netherlands. The latter is a one-off tax levied on so-called 'surplus profits' generated in 2022. The Group paid €65.7 million in cash taxes in 2022 (2021, €0.9 million), all relating to Dutch tax liabilities. Due to the timing of the GLA acquisition, no cash corporation tax was due or paid during 2022 in the UK.

As a result of the above, higher gas prices during the year, and adverse changes to the fiscal regime in the UK and the Netherlands, our current tax liability has increased from €15.0 million at the end of 2021 to €143.1 million at the end of 2022. This includes €46.9 million in respect of the Solidarity Contribution Tax. The payment of these liabilities and the normalisation of the timing of our tax payments will impact operating cash flow in 2023 and 2024.

The Group understands the introduction and implementation of the Solidarity Contribution Tax is subject to legal challenges by other parties. Furthermore, due to differences between DAS 270 of Dutch GAAP (the relevant revenue recognition standard for determining if the tax is due) and IFRS 15, the Group believes it has strong arguments that its Dutch subsidiary is out of scope of this tax (see note 6.3 to the financial statements). Therefore, it is not certain at this stage if the Group will be required to settle this tax liability, notwithstanding the inclusion of the tax charge as a liability in these financial statements.

Cash flow

€'000	Year ended 31 December 2022	Period ended 31 December 2021
Cash and cash equivalents at beginning of period	77,288	-
Net cash generated from operating activities	290,473	47,956
Net cash used in investing activities	(66,772)	(120,654)
Net cash from financing activities	(83,816)	149,986
Net increase in cash and cash equivalents	139,885	77,288
Foreign exchange losses	(5,193)	-
Cash and cash equivalents on 31 December 2022	211,980	77,288

 

ESG Outlook and Non-Financial Performance

Environment

Acting on climate change

We believe that natural gas has an important role to play in the energy transition, bridging the gap on the journey from fossil fuels to a renewable, zero-carbon future. To that end, we continue to explore ways to produce gas with a very low carbon footprint in an environmentally benign way as we seek to support the UK's and the Netherlands' net zero ambitions. In 2022 plans were made to invest to increase the wind generation capacity on our Q10-A offshore gas production platform by installation of a third wind turbine. This will be implemented during 2023.

Direct emissions and air quality

Our Scope 1 emissions levels are minimal, thanks to the solar panels and wind turbines that power the Q10-A platform. In 2022, we estimate the Scope 1 emissions related to our activities offshore the Netherlands were 0.002 kg CO₂e/boe excluding flaring. This represents a 55% reduction compared to 2021 mainly due to the increased use of renewable wind energy for the platform as opposed to the use of the standby diesel generator for power. Including flaring undertaken during our drilling campaign, we estimate the figure to be 0.279 kg CO₂e/boe. Including Scope 2 emissions, which relate primarily to the combustion of gas in compressors on the P15-D platform that used to process and export the gas production from Q10-A, we estimate the comparable figures to be 13.8 kg CO₂e/boe and 14.1 kg CO₂e/boe respectively.

Across the Q10-A platform in the Netherlands and the GLA offshore the UK, where Kistos has a non-operated interest, the Company's Scope 1 and Scope 2 emissions are significantly below the North Sea average. Furthermore, they are estimated to be c.62% lower than the CO₂ emissions associated with imported liquefied natural gas (LNG).

We have also implemented a programme to identify and prevent methane leaks from our operations with annual inspections, exceeding the four-year inspection requirement.

In our 2021 report, we published a number of goals related to reducing the GHG emissions from our offices and direct operations. In 2023, we plan to refurbish our office in The Hague. This will include the installation of an improved ventilation system, double glazing, and more energy efficient lighting and appliances.

Operational energy use

Our Q10-A platform is unmanned and is powered sustainably using solar energy and wind turbines. Compared to using diesel generators, Kistos estimates this saved approximately 41 tonnes of CO₂ emissions. Similarly, the Company estimates that its policy of conducting offshore visits via boat rather than helicopter saved more than 21 tonnes of CO₂ emissions. We continue to reduce CO₂ emissions through the reduced reliance on standby diesel power generation.

Spills and incidents

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. Until we have developed a 'no flaring' policy, we limit gas flaring as much as is practicable. During 2022, we experienced one overflow into an in-field separator at the onshore Hemrik facility. An investigation was launched immediately but, in line with our goal to have zero operational spills, no contaminants escaped into the environment.

Effluents and waste

We strictly adhere to guidelines compliant with EU REACH regulations in preventing the use of certain chemicals and materials that are considered harmful to the environment. In 2022, we continued to strive to reduce waste from our direct operations, in support of our goal to recycle more than two-thirds of our waste in our direct operations.

Biodiversity

We employ people to watch bird migrations and inform us when flaring during drilling operations can be conducted safely without affecting local wildlife. We also limit the ultrasonic sounds from our operations to prevent harm to local marine life and take specialist advice to keep seals away from our platforms. Striving to make a net positive impact on biodiversity throughout our direct operations, in 2022 we continued to explore practical steps to achieve this goal..

Social

Health and safety

Having incorporated third-party contractors into our safely culture, our HSE performance remains strong. In pursuit of our goal of zero harm to people in our direct operations, we had just one Lost Time Incident in 2022, as well as one incident of non-compliance, one near miss and one identified (non-reportable) hazard during six months of drilling and testing operations. The strict protocols and rigorous testing procedures we have in place to keep our employees and contractors safe have also ensured that our operations and offices have not been disrupted by COVID-19.

Employment

As a result of policies brought in during the pandemic, we now have a more 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. Therefore, a comprehensive employee satisfaction survey was conducted in 2022.

This was positive overall and confirmed that Kistos' employees experience a high degree of job satisfaction and appreciate the working atmosphere. Teamwork is good and people feel a high degree of job security, and a large majority of staff perceive their roles to necessary and useful. Vertical trust towards management has continued to grow following the integration of Tulip Oil into the Group.

We have taken action to address areas of concern identified by the survey, including issues with ergonomics and perceived workload. Furthermore, we have started work on setting up a comprehensive competence management system, through which we can demonstrate that Kistos has the competencies to perform our operations in a safe and professional manner.

Diversity, equality and inclusion

Diversity, equality and inclusion (DEI) is important to us. We have a roughly 75:25 male/female split across our workforce and we aim to enhance our approach to equality and equity across our business by developing a corporate DEI strategy. In 2022, we reviewed our policies to ensure equality and equity for all in our direct operations.

Stakeholder engagement

As well as ongoing dialogue with our employees and contractors, partners, suppliers and investors, all our activities require the involvement of the relevant regulatory bodies, the State Supervisor of Mines (SodM) in the Netherlands and the North Sea Transition Authority (NSTA) in the UK. We also work closely with Element NL and OEUK, which represent the interests of extractive companies operating in the Netherlands and UK respectively.

Other important stakeholder groups include the coastal communities who live near our operations, TotalEnergies as the operator of the GLA assets, listings agencies such as the Alternative Investment Market (AIM) and the Financial Conduct Authority (FCA), and the coastguards who patrol the waters in which our offshore assets are situated.

Governance

Governance

The Board is responsible for setting the Company's strategic aims, defining the business plan and strategy, and managing Kistos' financial and operational resources. Overall supervision, acquisition, divestment and other strategic decisions are determined by the Board. In conjunction with other Executive Directors, our Executive Chairman is charged with day-to-day responsibility for the implementation of the Company's strategy.

Risk management

Kistos identifies, assesses and manages the risks critical to its success. Overseeing these risks benefits the Group and protects its business, people and reputation. We use the risk management process to provide reasonable assurance that the risks we face are recognised and controlled. This approach enables the organisation to achieve its strategic objectives and create value.

Ethics, anti-corruption and bribery

We foster a culture that promotes ethical and responsible behaviour. We also work in locations where bribery and corruption are unlikely but nevertheless, we remain vigilant to the risk.

Funding and investment

Management regularly reviews the Group's cash forecasts and its covenants to ensure an adequate headroom of cash availability. Each project has a clear delivery framework with a responsible project lead. Delivery against the project objectives, timeline and cost are regularly monitored. Risks being faced are discussed and where appropriate risk mitigation steps implemented.

Procurement practices and sustainability of suppliers

We treat suppliers equally, without discrimination, promoting a 'one-team' culture. Where applicable, we work with suppliers pre-qualified for oil and gas operations. Kistos ensures any risks and costs borne by suppliers undertaking activities that support our business are proportional to the scope of the work.

Economic performance

Price volatility is both an opportunity and a risk to our business. While we benefit financially from the current rise in the price of gas, we still need to consider the wider impacts in terms of fuel poverty, the effect on manufacturing and the fertiliser industry.

Operations in sensitive or complex locations

The Group manages such risks in the context of upcoming developments through engagements with stakeholders. Where necessary, alternative options are also considered to allow for risk mitigation. External consultants with experience in managing these developments are employed to help complement the existing team skills.

Principal Risks and Risk Management

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

Overseeing these risks benefits the Group and protects its business, people and reputation. We use the risk management process to provide reasonable assurance that the risks we face are recognised and controlled. This approach enables the organisation to achieve its strategic objectives and create value. Depending on the nature of the risk, we may elect to accept the risk, manage it with controls or other mitigating actions, transfer the risk to others or remove risk as much as possible by ceasing those activities giving rise to the risks. The Directors confirm they have carried out a robust assessment of the principal risks facing the Group, including those that would significantly adversely impact its strategy, business model, future performance or liquidity.

 

Risk	Executive ownership	Mitigation	Change
Strategic
Political risk There are risks that changes in national government policies towards oil and gas-focused companies adversely impact the ability of the Group to deliver its strategy. This could result in challenges, delays and refusals related to permitting applications for development, appraisal and exploratory drilling in Kistos-owned or targeted blocks.	Peter Mann CEO	Directly and through Element NL, OEUK, BRINDEX and other industry associations, the Group engages with the respective governments and other appropriate organisations to ensure the Group is kept abreast of expected potential changes and takes an active role in making appropriate representations.	Risk has increased
Growth of reserves base The Group's growth strategy is dependent on identifying new reserves and resources, and does so through development and acquisition. Organic growth is focused on developing existing resources into producible reserves. As part of this growth strategy, there is a risk that the Group may fail to identify attractive acquisition opportunities or select inappropriate exploration work programmes. Exploration drilling may deliver adverse results due to factors including poor quality (or misinterpretation of) data, failure/underperformance of offshore vessels or other crucial equipment, unforeseen problems occurring during drilling and delays to offshore operations due to unfavourable weather. The long-term commodity price forecast and other assumptions used when assessing potential projects and investment opportunities can have a significant influence on the forecast return on investment. Inappropriately valued targets  may result in overpaying for acquisitions, leading to subsequent impairments of assets and goodwill and lead to adverse reputational and share price impact. Similarly, an inability to convert existing resources to reserves, or dry holes experienced during drilling campaigns, may give rise to impairments and reduce future forecast cash flows.	Andrew Austin Executive Chairman	The Group identifies and evaluates a broad range of acquisitions and similar opportunities and maintains strong relationships within the industry. Potential opportunities are evaluated internally and with support from subject matter experts where appropriate. A rigorous assessment process evaluates and determines the risks associated with all potential business acquisitions and strategic alliances, including conducting stress-test scenarios for sensitivity analysis. If applicable, each assessment includes an analysis of the Group's ability to operate in a new jurisdiction. Exploration, appraisal and development cases are robustly assessed and stress tested against cost, price and taxation sensitivities.	No change in risk
Climate change Changes in laws, regulations, policies, obligations and social attitudes relating to the transition to a lower carbon economy could lead to higher costs, or reduced demand and prices for gas, impacting the profitability of the Group. Sources of debt and equity finance may become more expensive or restricted as investors diversify away from oil and gas-based investments.	Peter Mann CEO	The Board actively reviews the Group's strategy towards energy transition with an aim to provide long‑term returns to shareholders, and regularly considers the impact of climate change and potential changes to policy in its decision making. It continues to investigate and implement actions on its existing assets that could reduce its environmental footprint, and environmental considerations are a key factor in determining any potential inorganic growth activity. The value of projects is discounted in the future for later life production to take into account possible reduced demand for hydrocarbons. The Group stress tests its budgets and forecasts in respect to the cost of carbon emission allowances.	No change in risk
Cyber security Breaches in, or failures of, the Group's information security management could adversely impact its business activities. The Group's information security management model is designed with defensive structural controls to prevent and mitigate the effects of computer risks. It employs a set of rules and procedures, including a Disaster Recovery Plan, to restore critical IT functions.	Richard Slape CFO	The Group outsources its provision of IT equipment and help-desk services to third parties. Various network management systems are used to protect the Group's IT environment.	No change in risk
Joint venture As a minority non-operating partner in the GLA partnership, the interests and objectives of the partners may not be aligned. This may result in longer decision making processes, programmes approved which are not in line with the Group's strategy and/or investment cases which the Group believes are in its best interests not voted through by partners.	Peter Mann CEO	The Group has representatives on all of the joint ventures' committees (including operating, finance and technical) and regularly engages with the joint-venture operator and other participants in the joint venture with regards to key decision and strategic direction.	New risk
Operational
HSE and compliance The Group is exposed to various risks in relation to HSE, compliance, planning, environmental, regulatory, licensing and other permitting rules associated primarily with production operations, drilling and construction. A loss of hydrocarbon containment, in addition to causing harm to the environment, could result in reputational damage and incur financial penalties.	Peter Mann CEO	The Group works closely with regulators to ensure that all required planning consents and permits for operations are in place and maintains continual dialogue with all stakeholders to understand emerging requirements. All activities are conducted in accordance with Board-approved policies, standards and procedures. The Group requires adherence to its Code of Conduct and runs compliance programmes to provide assurance on conformity with relevant legal and ethical requirements. The Group manages such risks in the context of upcoming developments through engagements with stakeholders. Where necessary, alternative options are also considered to allow for risk mitigation. External consultants with experience in managing these developments are employed to help complement the existing team skills. Potential development routes on existing production and new development opportunities are reviewed to maximise shareholder returns.	Increase in risk
Hydrocarbon production and operational performance The Group's production volumes (and therefore revenue) are dependent on the operational performance of its producing assets. The Group's producing assets are subject to operational risks, including no critical spare equipment or plant availability during the required plant maintenance or shutdowns; asset integrity and health, safety, security and environment incidents; and low reserves recovery from the field and exposure to natural hazards such as extreme weather events.	Peter Mann CEO	The Group continuously reviews production performance from each of its wells to enable it to predict well performance and plan well-intervention activities as needed. To the extent possible discussions are held with third parties to manage shutdowns both planned and unplanned. Planned and unplanned downtime assumptions are built into the corporate budgeting cycle and cash flow projections. Following acquisition of interests in the producing GLA assets, the Group's production base is diversified and thus is no longer exposed to a single source of revenue.	Decrease in risk
Project delivery Risk of delays in project delivery and higher costs being incurred, especially under the current high inflationary environment.	Peter Mann CEO	Each project has a clear project delivery framework with a responsible project lead. Delivery against the project objectives, timeline and cost are regularly monitored. Risks being faced are discussed and where appropriate risk mitigation steps implemented. Project costs are stress tested against cost increases with adequate contingency built in to estimates.	Increase in risk
Retention of key personnel The Group may not be able to retain key personnel, and there can be no assurance that the Group will be able to continue to attract and retain all personnel suitably qualified and competent necessary for the safe and efficient operation and development of its business.	Peter Mann CEO	The Board seeks to cultivate a safe, respectful working environment where people can thrive. Management has undertaken a benchmarking exercise on salaries to ensure that acquired staff are retained through a strong remuneration culture. Workplace surveys are undertaken to ascertain morale and employee concerns and allow management to swiftly address any issues. A long-term share incentive plan is now in place for key staff in the UK and the Netherlands.	No change in risk
Financial
Commodity price risk The Group's cashflow and results are heavily dependent on natural gas and other commodity prices, which are dependent on several factors including the impact of climate change concerns, geopolitics (including events such as the Russia-Ukraine conflict) and regulatory developments.	Richard Slape CFO	The Board continuously reviews the oil and gas markets to determine whether future hedges are needed and has the necessary contracts in place to undertake hedging activities if required. Cash flow projections and liquidity analyses are regularly tested for downside price scenarios.	No change in risk
Liquidity risk Adverse changes to production, commodity prices, taxation and surety bond requirements may put pressure on the Group's available liquidity, constraining its options to grow the business or, in the worst cases, cause it to breach its bond covenants or become insolvent.	Richard Slape CFO	Management regularly reviews the Group's cash forecasts and its covenants to ensure an adequate headroom of cash availability. The Group is in regular dialogue with potential providers of finance and surety bond providers.	No change in risk
Decommissioning costs and timing The future costs and timing of decommissioning is a significant estimate; any adverse movement in price, operational issues and changes in reserves and resource estimates could have a significant impact on the cost and timing of decommissioning. Where decommissioning costs are to be shared as part of a joint venture, risk of partners not fulfilling their commitments leaving remaining partners exposed. Changes to commodity prices, the taxation regime, inflation rates and other factors may mean that the Group is not be able to renew its surety bonds in respect of its DSA obligations, resulting in the Group having to cover its obligations fully in cash, restricting the amount of funds available for other opportunities and day-to-day operations.	Richard Slape CFO	The Group mitigates this risk through in-house decommissioning experience, coupled with a continued focus on delivering asset value to defer abandonment liabilities. Decommissioning security arrangements and postings in place for UK assets which mitigate risk from a regulatory and joint-venture partner perspective. The Group maintains strong relationships with surety bond providers and have obtained comfort that the surety market can continue to provide security for the expected DSA provisions.	No change in risk
Taxation Longer-term additional and increased taxes imposed on oil and gas companies by governments in reaction to so-called 'windfall profits' arising from short-term movements in commodity prices have led to a higher tax burden. Uncertainty over tax regimes may also hinder future investment decisions and reduce the returns from, and profitability of, operations. Should the Dutch tax office rule unfavourably against the Group with regards to the Solidarity Contribution Tax, this would have a material impact to the Group's projected cash position.	Richard Slape CFO	The Group engages with various industry bodies to raise concerns and suggest alternative approaches to proposed taxation policies. Projects and liquidity projections are modelled with various tax sensitivities in place. The Group engages the support and advice of external experts and legal counsel on taxation matters for areas where there exists significant uncertainty and judgement. The Group will review its investment strategy and may decide not to invest further in, or consider withdrawing from, jurisdictions with a recent history of significant tax changes, implementation of retrospective taxation, or where the taxation regime proves too burdensome.	New risk

 

Consolidated Financial Statements

Consolidated income statement

€'000	Note	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Revenue	2.1	411,512	89,628
Other operating income		11	61
Exploration expenses		(374)	(123)
Production costs	2.3	(22,927)	(6,143)
Development expenses	2.4	(1,752)	(4,456)
General and administrative expenses	3.2	(9,426)	(7,426)
Depreciation and amortisation	2.6	(83,234)	(13,277)
Impairments	2.8	(44,547)	(121,036)
Change in fair value and releases of contingent consideration	2.10.2	26,993	-
Operating profit/(loss)		276,256	(62,772)
Interest income	3.5	267	-
Interest expenses	3.5	(11,283)	(8,993)
Other net finance costs	3.5	(11,115)	(2,092)
Net finance costs		(22,131)	(11,085)
Profit/(loss) before tax		254,125	(73,857)
Tax (charge)/credit	6.1	(181,229)	33,749
Solidarity Contribution Tax charge	6.3	(46,935)	-
Total tax (charge)/credit	6.1	(228,164)	33,749
Profit/(loss) for the period		25,961	(40,108)
Basic earnings/(loss) per share (€)	3.1	0.31	(0.68)
Diluted earnings/(loss) per share (€)	3.1	0.31	(0.68)

 

Consolidated statement of other comprehensive income

€'000	Note	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Profit/(loss) for the period		25,961	(40,108)
Items that may be reclassified to profit or loss:
Losses on cash flow hedges	5.4	(9,404)	(38,624)
Hedging losses reclassified to profit or loss	5.4	21,185	26,843
Income tax on items of other comprehensive income	5.4	(5,891)	5,891
Foreign currency translation differences		(43)	382
Total other comprehensive income, net of tax		31,808	(45,616)

 

 

 

Consolidated balance sheet

€'000	Note	31 December 2022	31 December 2021
Non-current assets
Goodwill	2.7	10,913	-
Exploration and evaluation assets	2.7	43,338	45,771
Property, plant and equipment	2.6	282,474	171,227
Deferred tax assets	6.2	566	13,496
Investment in associates		61	-
Other long-term receivables		102	-
		337,454	230,494
Current assets
Inventories	4.5	9,688	902
Accrued income	4.2.1	47,962	40,299
Other receivables	4.2	6,600	8,439
Cash and cash equivalents	4.1	211,980	77,288
		276,230	126,928
TOTAL ASSETS		613,684	357,422
Equity
Share capital	5.3	9,464	9,627
Share premium	5.3	-	94,181
Merger reserve	5.3	140,105	14,734
Capital reorganisation reserve	5.3	(80,995)	-
Hedge reserve	5.4	-	(5,890)
Translation reserve	5.5	339	382
Share-based payment reserve	5.6	538	-
Retained earnings		33,261	(42,463)
Total equity		102,712	70,571
Non-current liabilities
Abandonment provision	2.5	123,503	15,904
Bond debt	5.1	80,800	145,074
Deferred tax liabilities	6.2	118,325	57,288
Other non-current liabilities	4.4	4,197	31
		326,825	218,297
Current liabilities
Trade payables and accruals	4.3	19,372	23,479
Current tax payable		143,134	14,980
Abandonment provision	2.5	2,585	1,272
Other liabilities	4.4	19,056	28,823
		184,147	68,554
Total liabilities		510,972	286,851
TOTAL EQUITY AND LIABILITIES		613,684	357,422

The notes on pages [xx] to [xx] are an integral part of these financial statements and were approved by the Board of Directors on [xx] 2023.

Andrew Austin   Executive Chairman

Consolidated statement of changes in equity

€'000	Note	Share capital	Share premium	Merger reserve	Capital reorganisation reserve	Hedge reserve	Translation reserve	Retained earnings	Share-based payment reserve	Total equity
At 14 October 2020		-	-	-	-	-	-	-	-	-
Loss for the period		-	-	-	-	-	-	(40,108)	-	(40,108)
Other comprehensive income		-	-	-	-	(5,890)	382	-	-	(5,508)
Total comprehensive income for the period		-	-	-	-	(5,890)	382	(40,108)	-	(45,616)
Transactions with owners
Shares issued in the period	5.3	9,627	94,181	14,734	-	-	-	-	-	118,542
Share issue costs	5.3	-	-	-	-	-	-	(2,355)	-	(2,355)
Total transactions with owners		9,627	94,181	14,734	-	-	-	(2,355)	-	116,187
At 31 December 2021		9,627	94,181	14,734	-	(5,890)	382	(42,463)	-	70,571
Profit for the year		-	-	-	-	-	-	25,961	-	25,961
Other comprehensive income		-	-	-	-	5,890	(43)	-	-	5,847
Total comprehensive income for the year		-	-	-	-	5,890	(43)	25,961	-	31,808
Transactions with owners
Capital reduction	5.3	-	(35,266)	(14,734)	-	-	-	50,000	-	-
Equity-settled share-based payments	3.4	-	-	-	-	-	-	-	538	538
Capital re-organisation	5.3	(163)	(58,915)	140,105	(80,995)	-	-	(237)	-	(205)
Total transactions with owners		(163)	(94,181)	125,371	(80,995)	-	-	49,763	538	333
At 31 December 2022		9,464	-	140,105	(80,995)	-	339	33,261	538	102,712

 

 

Consolidated cash flow statement

€'000	Note	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Cash flows from operating activities:
Profit/(loss) for the period		25,961	(40,108)
Tax charge/(credit)	6.1	228,164	(33,749)
Net finance costs	3.5	22,131	11,085
Depreciation and amortisation	2.6	83,234	13,277
Impairment charge	2.8	44,547	121,036
Change in contingent consideration payable	2.10.2	(26,993)	-
Share-based payment expense	3.4	538	-
Taxes paid		(65,729)	(890)
Abandonment costs paid	2.5	(2,319)	-
Increase in trade and other receivables		(1,382)	(40,990)
(Decrease)/increase in trade, other payables and provisions		(13,094)	18,582
Increase in inventories		(4,717)	(287)
Decrease in other non-current assets/liabilities		132	-
Net cash inflow from operating activities		290,473	47,956
Cash flows from investing activities:
Payments to acquire fixed assets		(19,454)	(19,958)
Acquisition of business	2.10	(40,047)	(100,696)
Payment of contingent consideration	2.10.2	(7,500)	-
Interest received		229	-
Net cash outflow from investing activities		(66,772)	(120,654)
Cash flows from financing activities:
Proceeds from share issue	5.3	-	102,441
Costs incurred for share issue	5.3	-	(2,355)
Repayment of long-term payables		(209)	(79)
Bond interest paid		(11,566)	(7,461)
Other interest paid	3.5	(268)	-
Proceeds from bond refinancing	5.1	-	3,000
Bond issue costs	5.1	-	(2,933)
Bond redemption costs and repurchase of own bonds	5.1.1	(71,773)	(2,627)
Proceeds from bond issue	5.1	-	60,000
Net cash (outflow)/inflow from financing activities		(83,816)	149,986
Increase in cash and cash equivalents		139,885	77,288
Cash and cash equivalents at start of period	4.1	77,288	-
Effects of foreign exchange rate changes		(5,193)	-
Cash and cash equivalents at end of period	4.1	211,980	77,288

 

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 contingent consideration assumed in a business combination, 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.

Kistos Holdings plc, a company registered in England and Wales under the Companies Act 2006 with registered company number 14490676, was incorporated on 17 November 2022 in England and Wales and its shares, with effect from 22 December 2022, are publicly traded on AIM in London. 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 consolidated financial statements of Kistos Holdings plc are presented as if the Company headed the new group for all of the current and prior reporting period. The change in parent company and legal capital of the group has been reflected in the statement of changes in equity.

These consolidated financial statements cover the calendar year 2022, which ended at the balance sheet date of 31 December 2022. The comparative period is the long period of account from 14 October 2020 to 31 December 2021.

 

1.2 Going concern

These financial statements have been prepared in accordance with the going concern basis of accounting. The forecasts and projections made in adopting the going concern basis take into account forecasts of commodity prices, production rates, operating and general and administrative (G&A) expenditure, committed and sanctioned capital expenditure, and the timing and quantum of future tax payments.

The Group's cash balances as at the end of April 2023 (the latest practicable date of preparing these financial statements) was €268 million. To assess the Group's ability to continue as a going concern, management evaluated cash flow forecasts for the period to December 2024 (the going concern period), by preparing a base case forecast and various downside sensitivities.

The base case going concern assessment assumed the following:

·      Q10-A production in line with latest internal forecasts, taking into account the results of the recently completed well intervention campaign which finished in March 2023;

·      GLA production in line with latest available operator forecasts;

·      Commodity prices based on observable forward curves prevailing at the latest practicable date;

·      Committed and contracted capital expenditure only (being primarily the costs of the Benriach well campaign currently underway and Mime's share of Balder X capital expenditure);

·      Obligations under Decommissioning Security Agreements (DSAs) for the GLA fields satisfied by the purchase of surety bonds in Q4 2023 (in respect of obligations for 2024) based on the most recent funding requirement and DSA model received from the operator, and at a similar cost to 2023;

·      Completion of the acquisition of Mime Petroleum (note 7.5.3) in July 2023 (for which there is only $1 upfront cash consideration, and any contingent consideration expected to be payable January 2025 at the earliest), with the Group assuming Mime's restructured debt from that point and consolidating Mime's expected future cashflows (including revenues from oil production, capital expenditure and corporation tax rebates); and

·      Settlement of the €47 million Solidarity Contribution Tax charge in Q2 2024 (notwithstanding that the Group believes it is out of scope of the charge).

This base case forecast demonstrated that the bond covenants (minimum liquidity and leverage ratio) were complied with and that the Group had sufficient cash to meet its obligations throughout the going concern period.

A key assumption within the forecast is the continued availability of surety bonds used to cover obligations under Decommissioning Security Agreements (DSAs). At 31 December 2022, the Group had €27.4 million of surety bonds in issue which are redetermined annually. The next redetermination takes place in June 2023, with renewed bonds (or other arrangements, if applicable) to be put in place by the end of 2023. 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 higher tax and inflation rates adversely impacting the calculation of the amount of security required. Based on the advice received, 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.

Various downside scenarios were also analysed, including reasonably possible commodity price and production downsides, and a scenario where the Group has to fully cover its estimated DSA obligations in cash. Individually these scenarios demonstrated an ability to meet the bond covenants and have sufficient cash available to continue in operational existence in the going concern period. If the estimated DSA obligations were required to be fully covered in cash and either the commodity price or production downside scenarios realised, then it is estimated that, with no mitigating activities undertaken, the Group may fall below its liquidity covenants in or around November 2024. A reverse stress test was also performed, which showed that either a reduction in sales volume or price of approximately 45% (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. However, as these potential breaches are forecast to occur shortly prior to the receipt of a material Norwegian cash tax rebate anticipated in December 2024, the Group is of the opinion that, should this combination downside scenario crystallise, it would be able to manage its liquidity position and avoid any breach via temporary working capital management. As outlined above, the Group believes the possibility that it will be unable to renew its surety bonds on the same basis as currently posted to be unlikely.

As a result of the above, the Directors have concluded that there is a reasonable expectation that the Group has adequate resources to continue in operational existence throughout the going concern period, and therefore the going concern basis is adopted in the preparation of these financial statements.

 

1.3 Significant events and changes in the year

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

·      The acquisition of a 20% interest in the Greater Laggan Area (GLA) producing gas fields and associated infrastructure alongside various interests in certain other exploration licences, including a 25% interest in the Benriach prospect, from TotalEnergies E&P UK Limited in July 2022, arising in the recognition of, among other assets and liabilities, €223.6 million of fixed assets, €115.0 million of decommissioning liabilities and €10.9 million of goodwill (note 2.10);

·      A significant increase in average realised sales prices and therefore significantly higher revenue as compared to the prior period due to increased commodity prices (note 2.1);

·      The recognition of €44.3 million of impairment charges to exploration and evaluation assets in the Netherlands segment following changes to the tax regimes making it more uncertain that the carrying value of those assets could be recovered through successful development (note 2.8);

·      An increase to the unit-of-production depletion charge rate in the Netherlands segment following a revision to the reserves base for depreciation purposes (note 2.6);

·      Gains of €27.0 million recognised in the income statement relating changes in contingent consideration payable (note 2.10.2), comprising a €19.5 million fair value gain relating to actualisation of the GLA acquisition payment linked to gas price, and a release of €7.5 million relating to the M10/M11 licence from the Tulip Oil acquisition (the corresponding asset for which was also fully impaired in the period);

·      A tax charge of €71.6 million arising from the introduction of the Energy Profits Levy (EPL) in the UK (note 6.2);

·      A tax charge of €46.9 million arising from the retrospective imposition of the Solidarity Contribution Tax in the Netherlands (note 6.1 and 6.3);

·      A capital reduction resulting in an increase to retained earnings of €50 million, a reduction to share premium of €35 million and a reduction to the merger reserve of €14 million (note 5.3); and

·      A capital reorganisation (being the incorporation of Kistos Holdings plc as the new controlling party of the Group) resulting in an increase in the merger reserve to €141.7 million and creation of a capital reorganisation reserve (note 5.3).

 

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).

These financial statements are presented in EUR, a currency different to the functional currency of the reporting entity (which is GBP), as a significant proportion of the consolidated results are attributable to subsidiaries whose functional currency is EUR, and the debt issued by members of the Group is denominated in EUR.

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 (except for long-term assets and liabilities which are translated at the historical rate);

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

·      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 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:

·      Property, Plant and Equipment: Proceeds before intended use - Amendments to IAS 16;

·      Reference to the Conceptual Framework - Amendments to IFRS 3;

·      Onerous Contracts - Cost of Fulfilling a Contract (Amendments to IAS 37); and

·      Annual Improvements to IFRS Standards 2018-2020.

The adoption of the 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.

 

1.6 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 2022, nor have they been early adopted. These standards and interpretations are not expected to have a material impact on the consolidated financial statements.

 

1.7 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 following are 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:

·      acquisition accounting - definition of a business and assessment of control (note 2.10);

·      identification of impairment indicators for fixed assets and goodwill (note 2.8); and

·      uncertain tax positions (note 6.3).

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 2.8);

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

·      the estimated cost for abandonment provisions (note 2.5).

The presumption of going concern is no longer deemed a significant judgement due to the strong cash balances of the Group and projected significant headroom over its debt covenants even taking into account downside sensitivities on commodity prices and production rates. See note 1.2 for further analysis of the assessment of going concern.

1.7.1 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. 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. Further details of the key price assumptions are outlined in note 2.8, including sensitivity analysis outlining the amount by which commodity prices would need to change to reduce the recoverable amount to the carrying amount of the assets being tested. Under current forecasts assuming the assets in their current condition, the Group's oil and gas assets are likely to be fully depreciated within five years, during which timeframe it is expected that global demand for gas will remain robust. Accordingly, the impact of climate change on expected useful lives of the Group's current assets is not considered to be a significant judgement or estimate. 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 2.8).

 

 

Section 2 Gas and oil operations

2.1 Revenue

€'000	Year ended 31 December 2022			14 October 2020 to 31 December 2021
	Geographical region
	Netherlands	UK	Total	Total
Sales of liquids	-	-	-	108
Sales of natural gas	285,053	126,459	411,512	89,520
Total revenue from contracts with customers	285,053	126,459	411,512	89,628

 All revenue in the prior period was attributable to the Netherlands region.

 

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, and therefore there are now 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; and

·      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. This segment was created during the year, following the acquisition completed in July 2022 (note 2.10).

The key measure of performance used by the Executive Directors to review segment performance 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 measures of total assets and liabilities by segment is 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 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 provisions for impairment, other non-cash charges such as depreciation and share-based payment expense, transaction costs and development expenditure. A reconciliation of Adjusted EBITDA by segment to profit before tax, the nearest equivalent IFRS measure, is presented below.

 

€'000	Note	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Netherlands Adjusted EBITDA		270,626	81,211
UK Adjusted EBITDA		112,899	--
Head office costs and eliminations		(3,510)	(2,350)
Group Adjusted EBITDA		380,015	78,861
Development expenses	2.4	(1,752)	(4,456)
Share-based payment expense	3.4	(538)	-
Depreciation and amortisation	2.6	(83,234)	(13,277)
Impairments	2.8	(44,547)	(121,036)
Transaction costs		(681)	(2,864)
Change in fair value and releases of contingent consideration	2.10.2	26,993	-
Operating profit/(loss)		276,256	(62,772)
Net finance costs		(22,131)	(11,085)
Profit/(loss) before tax		254,125	(73,857)

 

Transaction costs in the current period include:

·      costs relating to the GLA acquisition; and

·      costs incurred on a proposed transaction with Serica Energy plc, which did not proceed.

Transaction costs in the prior period relate to those costs incurred on the Tulip Oil acquisition.

 

2.2.3 Other segmental disclosures

€'000	Year ended 31 December 2022			14 October 2020 to 31 December 2021
	Netherlands	UK	Total	Total
Segment revenue	285,748	125,908	411,656	89,628
Inter-segment revenue	(144)	-	(144)	-
Revenue from external customers	285,604	125,908	411,512	89,628

 

All Netherlands segment external revenue in the current and prior period was derived from a single external customer. All UK segment revenue in the current year was derived from another single external customer.

 

€'000	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Income tax charge/(credit):
Netherlands	135,414	25,963
UK	121,740	-
Unallocated and consolidation adjustments	(28,990)	(59,712)
Total	228,164	(33,749)

 

2.3 Production costs

Production costs include:

·      the export of the gas produced from the Q10-A platform to a third-party platform, P15-D, including treatment tariff, compression tariff, CO₂ emission costs and fixed fees;

·      operating costs of the Shetland Gas Plant including support and services and emission costs;

·      well maintenance expenditures;

·      accounting movements in inventory and net realisable value adjustments;

·      capacity fees, tariffs and other transportation costs;

·      structural and facility-related surveys; and

·      G&A allocated to production costs.

 

2.4 Development expenses

Development expenses include the costs related to pre-Final Investment Decision (pre-FID) expenses incurred on front-end engineering and design related to:

·      potential alternative gas export routes from the Q10-A field;

·      Concept Assess and Concept Select phases of the Q10 Orion oil field development project; and

·      G&A allocated to development expenses.

 

2.5 Abandonment provision

€'000	Abandonment provision
At 1 January 2022	17,176
Acquisitions	115,004
Accretion expense	1,875
Changes in estimates to provisions	(1,877)
Utilisation	(2,319)
Effect of change to discount rate	(3,729)
Foreign exchange differences	(42)
At 31 December 2022	126,088
Of which:
Current	2,585
Non-current	123,503
Total	126,088

 

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 onshore pipelines and corresponding land from historic assets.

·      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 eight 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 licence or production consent had been concluded) and within one year for the onshore pipelines and land restoration. The removal and restoration of onshore pipelines and corresponding land is expected to take place within one year of the balance sheet date.

The abandonment of the UK fields and associated infrastructure is expected to take place between 5 and fourteen years from 31 December 2022 based on current production and commodity price forecasts and sanctioned development plans.

The utilisation of provisions in the period relates to the onshore abandonment of the onshore Donkerbroek-Hemrik location.

Abandonment provisions are initially estimated in nominal terms, based on management's assessment of publicly available economic forecasts and determined using an inflation rate of 2.5% (2021: 1.0%) and a discount rate of 2.5% to 3.5% (2021: 0.5%). The changes in estimates to provisions arises primarily as a result of the increased inflation rate assumed.

The Group has in issue €27.4 million of surety bonds as at 31 December 2022 (2021: nil) 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.

 

2.6 Property, plant and equipment

€'000	Assets under construction	Production facilities and wells	Other	Total
Cost
At 14 October 2020	-	-	-	-
Acquisition of business (note 2.10.1)	1,227	174,156	142	175,525
Additions	9,187	692	183	10,062
Other	-	151	-	151
Reclassifications	(10,414)	10,414	-	-
At 31 December 2021	-	185,413	325	185,738
Acquisition of business (note 2.10)	-	189,790	-	189,790
Additions	7,401	3,885	1,416	12,702
Disposals	-	(11,922)	(58)	(11,980)
Foreign exchange differences and other movements	-	(8,435)	-	(8,435)
At 31 December 2022	7,401	358,731	1,683	367,815
Accumulated depreciation and impairment
At 14 October 2020	-	-	-	-
Depreciation charge for the period	-	(13,161)	(116)	(13,277)
Provision for impairment (note 2.8)	-	(1,234)	-	(1,234)
At 31 December 2021	-	(14,395)	(116)	(14,511)
Depreciation charge for the period	-	(83,023)	(211)	(83,234)
Foreign exchange differences	-	734	3	737
Disposals	-	11,922	31	11,953
Provision for impairment (note 2.8)	-	(286)	-	(286)
At 31 December 2022	-	(85,048)	(293)	(85,341)
Net book value at 31 December 2021	-	171,018	209	171,227
Net book value at 31 December 2022	7,401	273,683	1,390	282,474

 

'Assets under construction' relates to wells drilled but not yet producing. The 'Other' category includes office and IT equipment, including assets (primarily office leases) held as right-of-use assets (note 5.2).

'Disposals' represent the removal of fully depreciated assets following the conclusion of the abandonment campaign on the location Donkerbroek Hemrik in Kistos NL1.

 

2.7 Intangible assets

€'000	Goodwill	Exploration and evaluation assets	Total
Cost
At 14 October 2020	-	-	-
Acquisition of business (note 2.10.1)	7,000	144,856	151,856
Additions	-	13,717	13,717
At 31 December 2021	7,000	158,573	165,573
Acquisition of business (note 2.10)	10,913	32,923	43,836
Additions	-	8,660	8,660
Other	-	245	245
At 31 December 2022	17,913	200,401	218,314
Accumulated amortisation and impairments
At 14 October 2020	-	-	-
Impairment	(7,000)	(112,802)	(119,802)
At 31 December 2021	(7,000)	(112,802)	(119,802)
Impairment	-	(44,261)	(44,261)
At 31 December 2022	(7,000)	(157,063)	(164,063)
Net book value at 31 December 2021	-	45,771	45,771
Net book value at 31 December 2022	10,913	43,338	54,251

Exploration and evaluation assets include the exploration licence portfolio acquired as part of the GLA acquisition, and the Orion oil prospect on the Q10-A licence. The Group's licences are outlined in note 2.9.

2.8 Impairment of assets and goodwill

 

Impairments of property, plant and equipment in the Netherlands segment of €0.3 million relate to a portion of the previously producing A01 well which, at the balance sheet date, had been partially abandoned in preparation for the drilling of a side-track.

Impairments of intangible exploration and evaluation assets in the Netherlands segment of €44.3 million comprise:

-       a full impairment of the carrying value attributed to the Q11-B exploration asset (€26.8 million);

-       a full impairment of the carrying value attributed to the Q10-B exploration asset (€10.0 million); and

-       a full impairment of the carrying value attributed to the M10/M11 exploration asset (€7.5 million).

The Q11-B and Q10-B assets have been impaired due to the scale, manner and nature of additional taxes introduced by the Dutch tax authorities. These increased taxes and levies have introduced uncertainty into what was previously a stable and predictable fiscal regime and, unlike equivalent measures in the UK, do not incentivise licence holders to invest further by means of enhanced deductions for capital expenditure. As budgeted spend on these assets has now been placed on hold pending further clarity on these measures and whether they are to be extended, and taking into account that during the previous year's drilling campaign the Q11-B appraisal well failed to produce gas from its primary target (but did have more successful tests from the Zechstein and Bunter formations), there is no longer sufficient certainty over whether the carrying value can be recovered from future development, therefore the amounts have been impaired in full.

The M10/M11 asset has been impaired because, as at the balance sheet date, the Group's application to renew the relevant licence had not been successful, and there is sufficient uncertainty as to whether the Group would be successful in its appeal and/or re-application. €7.5 million of contingent consideration payable (which would have crystallised upon confirmation by the Group to the vendor of the Group's intention to proceed with the exploitation of the M10/M11 licences by February 2022) has also been derecognised and a corresponding gain recognised as a separate line in profit and loss (see note 2.10.2).

The imposition of cijns in the Netherlands, and re-assessment of reserves on the Q10-A field, were considered by management to be impairment triggers for the Netherlands Production CGU. An impairment test was therefore undertaken, using a value-in-use method, which demonstrated that the recoverable amount exceeded the CGU's carrying amount and therefore no impairment charge was necessary. 

An impairment test was also carried out in respect of the UK Production and Development CGU, with the primary impairment indicator being the introduction, and subsequent increase and extension of, the Energy Profits Levy (increasing the effective tax rate applicable on the CGU from 40% at acquisition to 75%).

The recoverable amount of the CGU was determined by assessing the FVLCOD of the CGU, by way of discounted cash flow projections, in line with how other market participants would typically value such assets. The valuation is level 3 in the fair value hierarchy due to a number of unobservable inputs used in the estimate.

The key assumptions used in determining FVLCOD were as follows:

-       NBP gas price of 287p/therm in 2023, 218p/therm in 2024 and 138p/therm in 2025 based on independent forecasts and estimates prevailing at the balance sheet date;

-       production rates forecast by the asset operator, with the expected natural decline consistent with past performance, extending to the estimated cessation of production date (i.e. no growth rates applied);

-       decommissioning liabilities in line with the carrying value of the provisions at the balance sheet date; and

-       a post-tax discount rate of 13% reflecting the specific risks relating to the segment and geographical region.

The costs of disposal were not considered to be material for the purposes of the exercise.

The results of the impairment test were that the recoverable amount exceeded the carrying amount by €86 million. 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 60%; or

-       a reduction to projected production rate of approximately 60%.

2.9 Joint arrangements and licence interests

The Group has the following interests in joint arrangements that management has assessed as being joint operations. Following acquisition of the GLA assets, Kistos Energy Limited is the non-operational partner in joint arrangements with the operator, TotalEnergies E&P UK. Except where otherwise noted, the interest and status of licences is the same as at the end of the prior period.

Field or licence	Licence owner	Licence type	Status	Interest at 31 December 2022
M10a & M111	Kistos NL1 B.V.	Exploration	Operated	60%
Terschelling-Noord	Kistos NL1 B.V.	Exploration	Operated	60%
Donkerbroek	Kistos NL1 B.V.	Production	Operated	60%
Donkerbroek-West	Kistos NL1 B.V.	Production	Operated	60%
Akkrum-11	Kistos NL1 B.V.	Production	Operated	60%
Q07	Kistos NL2 B.V.	Production	Operated	60%
Q08	Kistos NL2 B.V.	Exploration	Operated	60%
Q10-A	Kistos NL2 B.V.	Production	Operated	60%
Q10-B	Kistos NL2 B.V.	Exploration	Operated	60%
Q11	Kistos NL2 B.V.	Exploration	Operated	60%
Laggan, Tormore, Edradour and Glenlivet (licences P911, P1159, P1195, P14532 and P1678)4	Kistos Energy Limited	Production	Non-operated	20%
Benriach (licences P2411 and P14532) 4	Kistos Energy Limited	Exploration	Non-operated	25%
Bunnehaven (licence P24153) 4	Kistos Energy Limited	Exploration	Non-operated	25%
Cardhu (licence P2594) 4	Kistos Energy Limited	Exploration	Non-operated	20%
Roseisle (licence P2604) 4	Kistos Energy Limited	Exploration	Non-operated	14%

¹ The Group does not hold the M10/M11 licence at the balance sheet date and is in the process of appealing the non-renewal of the licence.

² Licence P1453 is split into the portion including and excluding the Benriach area.

³ In process of being relinquished.

⁴ Acquired during the period.

In January 2023, Kistos NL2 B.V. was awarded the P12b, Q13b and Q14 exploration licences where it will act as operator with 60% interest.

2.10 Business combinations

To continue value creation for shareholders, on 10 July 2022, the Group completed the acquisition of a 20% working interest in the GLA licences, producing gas fields and associated infrastructure alongside various interests in certain other exploration licences, including a 25% interest in the Benriach prospect, 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 are as follows:

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

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 uplift is not tax deductible and therefore results in a net deferred tax liability and corresponding entry to goodwill.

Transaction costs of €0.4 million were incurred, recognised within 'General and administrative expenses' in the profit and loss account, and within operating cash flows in the cash flow statement.

The contingent consideration comprises 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, based on actual gas prices and production up to the acquisition date, forecast gas production for the balance of the year and an option pricing model using observable forward gas curves as at the acquisition date and forecast gas production for the balance of the year. At the balance sheet date all of the inputs to the contingent consideration calculation were available, and therefore it has been remeasured to the final settlement amount of €15.8 million, which was settled in cash in March 2023. The change in contingent consideration payable was driven primarily by movements in the gas price during the year as compared to the forward gas curves at the acquisition date. This contingent consideration has been classified as level 3 in the fair value hierarchy.

·      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, estimated based on the operator's P50 estimate of gross recoverable resources (638 Bcf), risk-adjusted to reflect management's assessment of chances of successful discovery and development, and discounted to present value based on the earliest estimated time that the contingent payment could crystallise. As at 31 December 2022, there has been no change in the amount recognised for the liability other than the interest accretion expense of €0.1 million (recognised within finance costs). This contingent consideration has been classified as level 3 in the fair value hierarchy.

 

2.10.1 Acquisition in prior period

On 20 May 2021, Kistos plc completed the 100% acquisition of Tulip Oil Netherlands B.V. (renamed to Kistos NL1) and Tulip Oil Netherlands Offshore B.V. (renamed to Kistos NL2) for consideration of €155.0 million. The acquisition consideration, management's assessment of the net assets acquired, and subsequent goodwill arising were as follows:

€'000	At acquisition date
Consideration:
Cash	124,225
Shares issued in Kistos plc	15,750
Contingent consideration	15,000
Total consideration	154,975
Net assets acquired:
Property, plant and equipment	175,525
Exploration and evaluation assets	144,856
Deferred tax assets	19,477
Cash and cash equivalents	23,529
Net working capital	1,163
Bond debt	(85,417)
Abandonment provisions	(14,158)
Deferred tax liabilities	(117,000)
Goodwill	7,000
Total net assets acquired	154,975

 

Contingent consideration of €15.0 million payable was recognised on acquisition, and comprised the following:

·      €7.5 million payable by February 2022 upon confirmation by Kistos of its intention to proceed with exploitation activities in respect of Vlieland Oil (Orion); and

·      €7.5 million payable by February 2022 upon confirmation by Kistos of its intention to retain ownership of the M10/M11 licences.

 

The contingent consideration in respect of Orion was paid during the current year. Contingent consideration relating to M10/M11 has been derecognised in full because, as at the balance sheet date, the Group had not been successful in its application to renew the relevant licences. Contingent consideration relating to the acquisition which was not recognised on the balance sheet is disclosed in note 7.2.

2.10.2 Movement in contingent consideration payable

The movement of contingent consideration balances is as follows:

€'000	GLA acquisition	Tulip Oil acquisition
At 14 October 2020	-	-
Recognised on acquisition	-	15,000
At 31 December 2021	-	15,000
Recognised on acquisition	38,029	-
Contingent consideration paid	-	(7,500)
Gain recognised following change in fair value	(19,493)	-
Accretion expense	153	-
Gain recognised following derecognition	-	(7,500)
Foreign exchange differences	375	-
At 31 December 2022	19,064	-

 

2.10.3 Contribution

The GLA acquisition contributed revenue of €125.9 million and a loss after tax of €20.1 million in the period from acquisition. If the acquisition had completed on 1 January 2022, consolidated revenue for the Group would have been €568.4 million. It has been considered impracticable to disclose the impact to consolidated profit and loss after tax if the acquisition had completed on 1 January 2022, due to the complexity of remeasuring the fair value of the acquired assets at 1 January and subsequent impact to depreciation, the complexity of measuring the contingent consideration payable at 1 January and subsequent impact to gain or loss on remeasurement, the combined impact of the above and other factors on the initial deferred tax liability recognised and subsequent deferred tax charge or credit and the lack of available information to determine the timing of certain expenditure for tax and EPL purposes. The impact to Adjusted EBITDA and EBITDA as if the acquisition had completed on 1 January 2022 is disclosed in Appendix B.

2.11 Commitments

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

€'000	31 December 2022	31 December 2021
Contractual commitments to acquire property, plant and equipment	2,553	1,400
Contractual commitments on intangible assets (including commitments on exploration assets)	27,483	-
Total	30,036	1,400

 

Section 3 Income statement

3.1 Earnings per share

	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Consolidated profit/(loss) for the period, attributable to shareholders of the Group (€'000)	25,961	(40,108)
Weighted average number of shares used in calculating basic earnings per share	82,863,743	58,867,726
Potential dilutive effect of:
Employee share options	135,989	-
Weighted average number of ordinary shares and potential ordinary shares used in calculating diluted earnings per share	82,999,732	58,867,726
Earnings/(loss) per share (€)	0.31	(0.68)
Diluted earnings/(loss) per share (€)	0.31	(0.68)

 

3.2 General and administrative expenses

€'000	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Salaries and contractors	6,598	3,114
Training, travel and subsistence	229	129
IT and communication	162	105
Professional services	2,657	4,238
Other (including recovery and capitalisation of costs)	(220)	(160)
Total other operating expenses	9,426	7,426

 

3.3 Employee benefit expenses 

€'000	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Wages and salaries	6,286	2,585
Social security costs	910	272
Equity-settled share-based payments (note 3.4)	538	-
Total employee benefit expenses	7,734	2,857

 

At the end of the period there were 24 employees (2021: 17 employees) of the Group (excluding Non-Executive Directors); 16 (2021: 12) in the Netherlands, two in Germany (2021: nil) and six (2021: five) in the United Kingdom.

The average number of employees in the Group is as follows:

	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Technical	14	4
Support	7	3
Management	3	3
Total staff	24	10

 

3.4 Share-based payment arrangements

During the year, the Group introduced share-based payment schemes for certain employees, which are outlined below. The total charge in respect of share-based payments for the year was €0.5 million (2021: nil).

Share option incentive awards (equity-settled)

On 1 February 2022, the Group established a share option programme that entitles all full-time employees of Kistos plc and Kistos NL2 to purchase shares of Kistos plc. Under this programme, holders of vested options are entitled to purchase shares at the option price of the shares once the options have vested. All options are to be settled by delivery of new shares.

Share option matching awards (equity-settled)

On 1 February 2022, the Group offered certain full-time employees in Kistos plc and Kistos NL2 to participate in an employee share purchase plan. To participate in the plan, the employees are required to buy, or already hold, shares of Kistos plc ('matched shares') with own funds. Under this programme, holders of vested options are entitled to purchase shares at the option price of the shares once the options have vested. All options are to be settled by delivery of new shares.

The key terms and conditions of the arrangements are as follows:

Share-based payment arrangement	Grant date	Number of shares	Vesting conditions	Contractual life of options
Incentive awards	14 February 2022	215,382	Employee remains in service during the vesting period. Option vest in equal instalments on the first, second and third anniversaries of the awards	10 years
Matching awards	25 April 2022	125,690	Employee remains in service during the vesting period and holds the equivalent number of matched shares at the vesting date.  Option vest in equal instalments on the first, second and third anniversaries of the awards	10 years

 

Measurement of fair values

Share option incentive awards (equity-settled)

The fair value of the share option programme has been measured using the Black-Scholes formula. Service and non-market performance conditions attached to the arrangements were not taken into account in measuring fair value.

The inputs used in the measurements of the fair values at grant date of the equity-settled share-based payment arrangements were as follows:

	Share-based payment arrangements
	Incentive awards	Matching awards
	2022	2022
Fair value at grant date in £	£2.27	£2.64
Share price at grant date	£3.57	£4.14
Exercise price	£2.73	£3.43
Expected volatility	49.83%	50.49%
Periods to exercise	10 years	10 years
Expected dividends	Not applicable	Not applicable
Risk-free interest rate (based on government bonds)	0.44%	1.12%

 

Expected volatility has been based on an evaluation of historical volatility of the share price, particularly over the historical period commensurate with the term between the initial public offering of Kistos plc's shares and the grant date(s) of the share-based payment programme(s). No expected dividends were included in the option pricing model as the granting entity has no history of paying dividends. Based on lack of historical data, it is expected that all employees remain in place during the scheme and will have a maximum of 10 years to exercise the options. At 31 December 2022, no employees have left the employer that participate in the share option programme(s).

Following the capital reorganisation, the terms of the share options were modified such that once the share options have vested and upon their exercise, they will be settled in ordinary shares of Kistos Holdings plc instead of Kistos plc. However, as the reorganisation was an exchange of ordinary shares in Kistos Holdings plc for those of Kistos plc (with each share having the same economic and voting rights) it was determined that there was no change to the fair value of share options as a result of this modification.

Reconciliation of outstanding share options
As at 31 December 2022 the following share options are outstanding, as the date of the first anniversary has not yet been reached, none of these share options have been vested. Based on the vesting conditions, requiring at least three years of service for the full share options awards, the costs of share-based payments are front-loaded.

	Incentive awards	Matching awards
Outstanding at 1 January 2022	-	-
Share options first anniversary	65,813	38,405
Share options second anniversary	32,907	19,203
Share options third anniversary	21,938	12,802
Outstanding at 31 December 2022	120,658	70,410
Fair value per share €	€2.71	€3.13

Upon vesting of the share options and exercise by the employee, the obligation will be settled by Kistos Holdings plc.

 

3.5 Interest and other net finance costs

€'000	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Interest income	(267)	-
Total interest income	(267)	-
Bond interest payable	10,543	8,900
Bank charges and other interest expense	268	93
Surety bond interest	472	-
Total interest expenses	11,283	8,993
Accretion expense on abandonment provisions and other liabilities (note 2.5 and 2.10.2)	2,028	43
Accretion expense on lease liabilities	42	2
Amortisation of bond costs (note 5.1)	1,062	700
Hedge ineffectiveness recognised in income statement	-	625
Net foreign exchange losses/(gains)	1,569	(59)
Loss on bond redemption (note 5.1.1)	6,414	-
Loss on bond modification	-	781
Total other net finance costs	11,115	2,092
Total	22,131	11,085

 

 

Section 4 Working capital

4.1 Cash and cash equivalents

Cash and cash equivalents consist of bank accounts and restricted cash balances. The restricted funds at the end of 2021 and 2022 relate to a bank guarantee for the office lease in The Hague.

€'000	31 December 2022	31 December 2021
Bank accounts	211,958	77,266
Restricted funds	22	22
Cash and cash equivalents	211,980	77,288

 

4.2 Trade and other receivables

€'000	31 December 2022	31 December 2021
Receivables due from joint operation partner	3,198	3,920
Other receivables	1,594	2,014
Prepayments	679	163
VAT receivable	1,129	2,342
Total other receivables	6,600	8,439

 

4.2.1 Accrued income

The accrued income balance of €48.0 million (2021: €40.3 million) represents amounts due to the Group in respect of gas sales revenue which had not been invoiced at the balance sheet date. All accrued income amounts had been invoiced and collected in full within one month of the corresponding reporting date.

Information about the Company's exposure to credit risk and impairment losses for other short-term receivables is included in note 4.6.

4.3 Trade payables and accruals

€'000	31 December 2022	31 December 2021
Trade payables	7,271	9,018
Accruals	12,101	14,461
Total trade payables and accruals	19,372	23,479

 

Trade payables are unsecured and generally paid within 30 days. Accrued expenses are also unsecured and represents estimates of expenses incurred but where no invoice has yet been received. The carrying value of trade payables and other accrued expenses are considered to be fair value given their short-term nature.

4.4 Other liabilities

€'000	31 December 2022	31 December 2021
Bond interest payable	831	1,854
Hedge liability	---	11,781
Salary and salary-related liabilities	202	97
Contingent consideration (note 2.10.2)	15,796	15,000
Joint operator payable	1,945	-
Lease liabilities	282	91
Other liabilities - current	19,056	28,823
Contingent consideration	3,268	-
Other loans	-	31
Lease liabilities	929	-
Other liabilities - non-current	4,197	31

 

The interest on bond debt is payable semi-annually. The hedge liability represented the fair value liability in respect of the cash flow hedge for the remaining period of the gas price hedge contract. As at 31 December 2022 the hedge liability is nil, as no hedges are in place in respect of future production.

4.5 Inventory

€'000	31 December 2022	31 December 2021
Spares and supplies	3,896	775
Crude oil and natural gas liquids	5,792	127
Total inventory	9,688	902

 

No inventory was recognised as an expense in the current or prior year. The movement in inventory net realisable value provisions amounted to a charge of €0.8 million (2021: nil).

4.6 Financial instruments and financial risk management

4.6.1 Financial risk management objectives

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

4.6.2 Financial assets and liabilities carried at fair value

The following table shows the fair values of financial liabilities which are carried at fair value, including their levels in the fair value hierarchy. The Group holds no financial assets recognised and measured at fair value.

 

€'000	Level 1	Level 2	Level 3	Total
Financial liabilities
Contingent consideration - GLA acquisition	-	-	19,064	19,064
Total at 31 December 2022	-	-	19,064	19,064
Contingent consideration - Tulip Oil acquisition	-	-	15,000	15,000
Hedging derivatives	-	-	11,781	11,781
Total at 31 December 2021	-	-	26,781	26,781

 

4.6.3 Risk management framework

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

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

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

4.6.4 Market risk

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

Currency risk

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

Entities within the Group undertake transactions in currencies other than their functional currency, which gives rise to transactional currency risk. The Group manages this risk to an extent by holding certain amounts of cash in currencies other than the entity's functional currency to act as an economic hedge against foreign exchange movements. From time to time, the Group may use instruments or derivatives to hedge specific future foreign currency payments or receipts; however, no such transactions were entered into during the current or prior period.

As at 31 December 2022, 49% of the Group's cash and cash equivalents was held in EUR (31 December 2021: 60%).

A reasonably possible strengthening or weakening of GBP at 31 December 2022 would have affected the measurement of monetary items denominated in a foreign currency and affected equity and profit or loss by the amounts shown below. This analysis assumes that all other variables, in particular interest rates, remain constant, and ignores any impact of forecast sales and/or expenses. The exposure to other foreign currency movements is not material.

€'000	Profit or loss		Equity, net of tax
31 December 2022	Strengthening	Weakening	Strengthening	Weakening
GBP (10% movement)	10,499	(10,499)	1,073	(1,073)

 

Interest rate risk

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

The Group is exposed to interest rate movements through its cash and cash equivalents deposits which earn (and, where interest rates are below zero, are charged) interest at variable interest rates.

The Group's borrowings carry fixed rates of interest (note 5.1) and thus there is no interest rate exposure thereon.

For the year ended 31 December 2022, it is estimated that a 1% increase in interest rates would have increased the Group's profit after tax by approximately €0.2 million, and a 1% decrease would have reduced the Group's profit after tax by approximately €0.2 million. This sensitivity has been calculated on the assumption that the amount of cash and cash equivalents on the Group's interest-bearing accounts at the balance sheet date had been in place for the whole year. The impact on equity would be the same as the impact on profit after tax.

Other price risks - commodity price risk

Commodity risk predominantly arises from the sale of natural gas from the Group's interest in the Q10-A and GLA fields, as the price realised from the sale of natural gas is determined primarily by reference to quoted market prices on the day and/or month of delivery.

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

In 2021, Kistos NL2 hedged monthly production from the Q10-A (being the hedged item) at an amount of 100,000 MWh per month at a price of €25/MWh (being the hedged instrument) for the nine-month period from July 2021 to March 2022. Kistos NL2 engaged in this cash flow hedge to cover the potential volatility of the gas price and the impact that this may have on the concurrent capital expenditure programme. In the current period, the hedge was effective (2021: €0.6 million of hedge ineffectiveness was recognised within net finance costs).

As at 31 December 2022, the Group had no commodity price hedging arrangements in place.

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

Credit risk

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

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

The Group held cash and cash equivalents of €212.0 million as at 31 December 2022 (2021: €77.3 million). As at 31 December 2022, 99% of the Group's cash and cash equivalents are held with bank and financial institution counterparties which have an investment grade credit rating.

Impairment on cash and cash equivalents has been measured on a 12-month expected loss basis and reflects the short maturities of the exposures. The Group considers that its cash and cash equivalents have low credit risk based on external credit ratings of the counterparties.

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

4.6.6 Liquidity risk

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

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

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

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

In addition to the amounts held on balance sheet, the Group has in issue €27.4 million of surety bonds as at 31 December 2022 (2021: nil) to cover its obligations under Decommissioning Security Agreements (DSAs) for the GLA fields and infrastructure. Should the Group be in default under the DSAs resulting in the bond provider being required to pay out on those bonds, the Group would be required to indemnify the providers by paying cash to cover their liability. If the surety market were to deteriorate such that the Group is unable to renew its bonds, the various DSAs would require the Group to post cash into trust the equivalent value.

4.7 Maturity analysis of financial liabilities

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

€'000	Within 3 months	3 months to 1 year	1-5 years	More than 5 years	Total
Bond debt	-	7,379	98,319	-	105,698
Contingent consideration	15,796	-	-	6,191	21,987
Other liabilities	2,147	-	-	-	2,147
Lease liabilities	75	308	1,110	-	1,493
Trade payables and accruals	19,372	-	-	-	19,372
At 31 December 2022	37,390	7,687	99,429	6,191	150,697
Bond debt	-	7,379	169,144	-	176,523
Other non-current liabilities	-	-	31	-	31
Contingent consideration		15,000	-	-	15,000
Other liabilities	120	68	-	-	188
Trade payables and accruals	23,479	-	-	-	23,479
At 31 December 2021	23,599	22,447	169,175	-	215,221

 

Section 5 Capital and debt

5.1 Bond debt

€'000	€90 million bond	€60 million bond	Bond costs	Total
Opening balance	-	-	-	-
Acquisition of business (note 2.10.1)	86,497	-	(1,080)	85,417
Proceeds from bond issue	3,000	60,000	-	63,000
Transaction costs	-	-	(2,588)	(2,588)
Amortisation of bond costs	-	-	700	700
Interest	893	-	-	893
Modification of bond terms	(2,348)	-	-	(2,348)
At 31 December 2021	88,042	60,000	(2,968)	145,074
Amortisation of bond costs	-	-	1,062	1,062
Interest	23	-	-	23
Derecognition on repurchase	(65,359)	-	-	(65,359)
At 31 December 2022	22,706	60,000	(1,906)	80,800

 

During 2021, Kistos NL2 refinanced an existing €87 million bond with a new €90 million bond, denominated in EUR with a tenor from May 2021 to November 2024. Interest is paid on a semi-annual basis.

Following the acquisition of Kistos NL1 and Kistos NL2 in 2021, a new €60 million bond was issued by Kistos NL2 that runs from May 2021 to May 2026, denominated in EUR with an interest rate of 9.15% per annum. Interest is paid on a semi-annual basis. Kistos NL1 and Kistos plc are guarantors. Each guarantor irrevocably, unconditionally, jointly and severally:

·      guarantees to the bond trustee the punctual performance by Kistos NL2 of all obligations related to the bonds;

·      agrees to make payment to the bond trustee on request in the event of non-payment by Kistos NL2, together with any default interest; and

·      indemnifies the Bond Trustee against any cost, loss or liability incurred in respect of the obligations of Kistos NL2.

Kistos NL2 has issued a security in favour of the bond trustee over its assets for both bonds, including a pledge over all intercompany receivables between Kistos NL2 and Kistos NL1 and Kistos plc. In addition, a Netherlands Pledge has been provided to the bond trustee covering all receivables of Kistos NL2 and Kistos plc.

 

				31 December 2022		31 December 2021
€'000	Currency	Nominal interest rate	Year of maturity	Face value	Carrying amount	Face value	Carrying amount
€90 million bond	€	8.75%	2024	21,572	22,706	90,000	88,042
€60 million bond	€	9.15%	2026	60,000	60,000	60,000	60,000
Total				81,572	82,706	150,000	148,042

 

The face value of the 8.75% 2024 bonds as at balance sheet date is presented net of €21.6 million of bonds repurchased (but not cancelled).

The fair value of the non-current borrowings is €85.4 million as at 31 December 2022, based on quoted prices available. They are classified as level 1 fair values in the fair value hierarchy as they are listed on the Oslo Børs.

5.1.1 Repurchase of bonds

During 2022, the Group repurchased €68.4 million in nominal value of its €90 million bonds at an average price of 104.9%. Although the bonds cannot be cancelled, the liability relating to the repurchased amount has been treated as being extinguished, and a loss on repurchase of €6.4 million has been recognised in the income statement due to the bonds being repurchased at a premium.

The net loss on repurchase of the bonds is reconciled as follows:

	€'000
Total cash consideration paid	73,942
Less: settlement of accrued interest	(2,169)
Cash consideration paid for repurchase of bond principal	71,773
Carrying value of bond derecognised	(65,359)
Loss on repurchase of bond	6,414

 

5.1.2 Covenants

€90 million bond	Requirement	Effective date
Issuer (Kistos NL2)
Minimum liquidity	10,000,000	At all times
Maximum leverage ratio	2.50	From and including 1 January 2022 tested at 30 June and 31 December
Group (Kistos consolidated)
Minimum liquidity	20,000,000	At all times
Maximum leverage ratio	3.50	From and including 30 June 2022 and 31 December

 

€60 million bond	Requirement	Effective date
Issuer (Kistos NL2)
Minimum liquidity	10,000,000	At all times
Maximum leverage ratio	2.50	From and including 30 June 2022 and 31 December
Group (Kistos consolidated)
Minimum liquidity	20,000,000	At all times
Maximum leverage ratio	3.50	From and including 30 June 2022 and 31 December

 

During 2022 and 2021, Kistos NL2 and Kistos plc complied with the minimum liquidity covenant at all times. On 31 December 2022, the Group had a leverage ratio of (4.23), calculated as follows:

               

Covenant calculation	2022
Group pro forma EBITDA for the year 2022 (Appendix B1)	541,224
Borrowings	82,706
Lease liabilities (note 5.2)		1,211
Cash and cash equivalents (note 4.1)	(211,980)
Net (cash)/debt for leverage ratio test at 31 December 2022	(128,063)
Leverage ratio	(4.23)

 

5.2 Leases

€'000	31 December 2022	31 December 2021
Right-of-use assets
Offices	1,181	91
Other	46	-
Total	1,227	91
Lease liabilities
Current	929	91
Non-current	282	-
Total	1,211	91

 

Lease liabilities are included within 'other liabilities' on the balance sheet, and right-of-use assets are included within the 'other' underlying class of property, plant and equipment.

The total amount of depreciation charged in respect of right-of-use assets was €180 thousand (2021: €90 thousand). The total cash outflow for leases was €181 thousand (2021: €98 thousand). Expenses relating to low-value and short-term leases was not material.

During 2022, additions of €1.3 million were made to right-of-use assets (2021: not material), primarily relating to the lease of the Group's new head office in London.

5.3 Share capital, share premium and other capital reserves

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

	Number of shares	Share capital (€'000)	Share premium (€'000)	Merger reserve (€'000)	Capital reorganisation reserve (€'000)
Issue of shares 10 November 2020	8,500,000	987	3,949	-	-
Issue of shares 25 November 2020	31,750,000	3,689	33,192	-	-
Issue of shares 20 May 2021	42,613,743	4,951	57,040	14,734	-
At 31 December 2021	82,863,743	9,627	94,181	14,734	-
Issue and cancellation of bonus shares	-	-	14,734	(14,734)	-
Capital reduction	-	-	(50,000)	-	-
Capital reorganisation	-	(163)	(58,915)	140,105	(80,995)
At 31 December 2022	82,863,743	9,464	-	140,105	(80,995)

 

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

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

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

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

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

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

5.4 Hedge reserve

€'000	31 December 2022	31 December 2021
Balance at beginning of the period	(5,890)	-
Cost of hedging deferred and recognised in OCI	11,781	(11,781)
Deferred tax on hedge reserve in OCI	(5,891)	5,891
Balance at end of the period	-	(5,890)

 

The hedging reserve represents the change in value of the hedged items (production) discounted cash flows at the forward gas prices curve between inception date, year end and fixed hedged instrument (100,000 MWh of production) discounted cash flow. Amounts that are effective and realised have been taken into the profit and loss account within gas sales (revenue). During 2022, no hedge ineffectiveness has arisen (2021: €0.6 million).  The hedge reserve has been taxed at an effective rate of 50%.

Kistos NL2 held the following cash flow hedge during 2022:

	Volume (MWh)	Price	Period of hedge
Cash flow hedge	300,000	€25 MWh	Jan-Mar 22

 

The hedge was equally distributed over each month at 100,000 MWh. As at 31 December 2022, all hedges had expired.

5.5 Translation reserve

The translation reserve comprises all foreign currency differences arising from the translation of the financial statements of foreign operations, as well as the effective portion of any foreign currency differences arising from hedges of a net investment in a foreign operation.

5.6 Share-based payment reserve

The share-based payment reserve relates to share-based payment programmes introduced during 2022 to all full-time employees of Kistos plc and Kistos NL2 B.V. The obligation will be settled by Kistos Holdings plc upon exercise of the share options by the employees. The corresponding entry to the share-based payment reserve is the charge of share-based payment expense (note  3.4).

Section 6 Tax

6.1 Tax charge or credit for the period

€'000	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Current tax
Current tax expense for current year	195,531	14,091
Total current tax	195,531	14,091
Deferred tax
Decrease in deferred tax assets	7,039	11,872
Increase/(decrease) in deferred tax liabilities	25,594	(59,712)
Total deferred tax	32,633	(47,840)
Tax charge/(credit)	228,164	(33,749)

 

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

€'000	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Profit/(loss) before taxes	254,125	(73,857)
Income tax (charge)/credit calculated at the domestic tax rate applicable to entity (2021: calculated at 50%)	(142,880)	36,929
Investment allowances and other enhanced deductions	7,471	2,239
Income and expenditure not taxable or deductible	21,799	-
Difference in tax rates	-	(2,712)
Utilisation of losses	7,021	-
Other movements	--	(1,045)
Losses not recognised	(3,406)	(1,662)
Impact of Energy Profits Levy in the UK	(71,573)	-
Solidarity Contribution Tax charge (note 6.3)	(46,935)	-
Other changes to tax rates	339	-
Tax (charge)/credit	(228,164)	33,749
Effective tax rate	89.8%	45.7%

 

The applicable domestic tax rates for the year ended 31 December 2022 are 50% for entities within the Netherlands, 65% for ring-fence entities within the UK and 19% for non-ring-fence entities within the UK. In the prior year a rate of 50% was used, being the combined rate of tax applicable oil and gas activities in the Netherlands as the impact of tax on head office activities incurred within the UK was not material.

 

6.2 Deferred tax

€'000	31 December 2022	31 December 2021
Deferred tax liability at beginning of period	57,288	--
Recognised on acquisition (note 2.10)	36,781	117,000
Profit and loss account	25,594	(59,712)
Foreign exchange differences	(1,338)	-
Deferred tax liability at end of period	118,325	57,288

 

The fair value of the deferred tax liability in the GLA acquisition acquired amounted to €36.8 million. The deferred tax liability was calculated based on a 40% tax rate which was the substantively enacted rate prevailing at the date of acquisition. In the prior period, the fair value of the deferred tax liability in the Tulip Oil acquisition was recognised based on a tax rate of 50%.

€'000	Temporary differences
	Tax losses	Provisions	Other	Total
At 14 October 2020	-	-	-	-
Recognised on acquisition (note 2.10.1)	14,802	2,765	1,910	19,477
Deferred tax on hedge reserve in OCI (note 5.4)	-	-	5,891	5,891
Profit and loss account	(7,787)	1,403	(5,488)	(11,872)
Deferred tax asset at 31 December 2021	7,015	4,168	2,313	13,496
Deferred tax on hedge reserve in OCI (note 5.4)	-	-	(5,891)	(5,891)
Profit and loss account	(7,015)	(697)	673	(7,039)
Deferred tax asset at 31 December 2022	-	3,471	(2,905)	566

 

The tax losses are made up of Corporate Income Tax (CIT) and State Profit Share (SPS) losses in the Netherlands. The 'Provisions' category relates to temporary differences on abandonment provisions. The 'Other' category relates to temporary differences on property, plant and equipment, abandonment fixed assets and other provisions/liabilities.

CIT losses can be carried forward indefinitely. Some losses in Kistos NL1 cannot be utilised and hence have not been recognised. This amounts to €1.0 million (2021: €1.9 million).

Tax losses of €5.4 million arising in Kistos Holdings plc have not been recognised due to the uncertainty of future profits and where they may arise from.

6.2.1 Changes to tax rates

In November 2022, the UK Government announced changes to the Energy Profits Levy (EPL), increasing the rate from 25% to 35%, applied to those entities within the ring-fence effective from 1 January 2023, and extending the period applicable to 31 March 2028, with no provision for earlier withdrawal of the levy. The new law became substantively enacted on 30 November 2022. The tax rate applicable to UK entities outside of the ring-fence will increase from 19% to 25% with effect from 1 April 2023. Where applicable, UK deferred tax balances at the balance sheet date have been remeasured using these tax rates.

6.3 Uncertain tax positions

Section 7 Other disclosures

7.1 Related party transactions

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

7.1.1 Compensation of Directors and key management personnel

The Directors of the Kistos Group are the only key management members. The function of the Directors of Kistos NL1 and Kistos NL2 is provided by certain management companies and staff employed by Kistos plc for which recharges to the Group companies based on time spent are made.

The Group is wholly and directly controlled by Kistos Holdings plc.

€'000	Year ended 31 December 2022	14 October 2020 to 31 December 2021
Short-term employee benefits	2,607	935
Post-employment benefits	191	30
Total Directors' remuneration	2,798	965
Fees payable to management companies for director services	39	42
Total key management personnel compensation	2,837	1,007

 

No long-term benefits, termination benefits or share-based payment expense was recognised in respect of the Directors. Further information for Directors' remuneration is provided in the Remuneration Report within the Annual Report and Account for 2022 (figures in which are presented in GBP). The highest-paid Director had total remuneration for the period of €938 thousand (2021: €490 thousand).

7.1.2 Loans to key management personnel

 

€'000	Year ended 31 December 2022	14 October 2020 to 31 December 2021
At start of the period	238	-
Loans made	-	238
Foreign exchange movements	(12)	-
At end of the period	226	238

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

7.1.3 Other related party transactions

During the period the Group paid €56 thousand of rental and other property-related costs (2021: €28 thousand) in respect of premises owned by a member of key management personnel. No amounts were outstanding at the period end.

7.2 Contingencies

As part of the acquisition of Tulip Oil (note 2.10) the following contingent payments could be made to the vendor should certain events and milestones take place:

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

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

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

Based on management's current assessments and current status of the projects and developments above, the contingent considerations above remain unrecognised on the balance sheet. All contingent payments relating to the GLA acquisition have been recognised on the balance sheet.

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

7.3 Reconciliation of liabilities arising from financing activities

€'000	€90 million bond	€60 million bond	Bond interest payable	Amortised bond costs	Other non-current liabilities	Lease liabilities
Opening balance	-	-	-	-	-	-
Liabilities acquired (note 2.10)	86,497	-	584	(1,080)	110	75
Financing cash flows	3,000	60,000	(7,461)	(2,933)	(79)	-
Interest expense on liability	893	-	8,731	-	-	-
Amortisation of bond costs	-	-	-	700	-	-
Modification of bond terms	(2,348)	-	-	-	-	-
Other movements	-	-	-	345	-	16
At 31 December 2021	88,042	60,000	1,854	(2,968)	31	91
Financing cash flows	(71,773)	-	(11,566)	-	(31)	(178)
Loss on bond repurchase	6,414	-	-	-	-	-
Interest expense on liability	23	-	10,543	-	-	-
Amortisation of bond costs	-	-	-	1,062	-	-
New leases entered into	-	-	-	-	-	1,297
At 31 December 2022	22,706	60,000	831	(1,906)	-	1,210

 

7.4 Auditor's remuneration

During the year, the company and its subsidiaries obtained the following services from its auditors and affiliates:

€'000	Year ended 31 December 2022	Year ended 31 December 2021
Audit fees
Audit of the consolidated and company financial statements	154	176
Audit of the financial statements of the subsidiaries	340	227
Total audit fees	494	403
Non-audit fees
Due diligence services	-	240
Other assurance services	20	-
Tax services	-	12
Total non-audit fees	20	252
Total	514	655

 

7.5 Subsequent events

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

7.5.1 Completion of Q10-A work programme

In March 2023, the Valaris 123 rig demobilised from the Q10-A field having undertaken a work programme of side-tracks and well stimulations. The results of the campaign were mixed due to mechanical issues arising from utilising the existing well stock rather than reservoir performance issues. The results of this campaign are still being analysed by the Group and, once fully evaluated, will inform the decision on the timing and nature of future capital expenditure on the field.

7.5.2 Benriach well

On 21 March 2023, the Transocean Barents rig spudded the Benriach exploration well, in which the Group has a 25% interest.

7.5.3 Acquisition of Mime Petroleum

On 18 April 2023, the Group conditionally agreed to acquire 100% of the issued and to be issued share capital of Mime Petroleum A.S. (Mime) from Mime Petroleum S.a.r.l. Mime is a company focussed on exploration, development and production projects on the Norwegian Continental Shelf, and holds a non-operated 10% interest in the Balder joint venture (comprising the Balder and Ringhorne fields, including the Balder X project) and a 7.4% stake in the Ringhorne East unit, all operated by Vår Energi A.S.A. Mime's share of hydrocarbon production from Balder and Ringhorne is expected to be approximately 2,000 boe/d in 2023. The Balder X project comprises the Balder Future and Ringhorne Phase IV drilling projects and is designed to extend the life of the Balder Hub. It includes upgrading the Jotun FPSO, which is forecast by the operator to sail away in the first half of 2024 and achieve first oil later that year.

The consideration for the transaction is $1 plus the issue of up to 6 million warrants exercisable into new ordinary shares of Kistos Holdings plc at a price of 385p each. 3.6 million of the warrants can be exercised between completion of the transaction and 18 April 2028. The balance of warrants are exercisable from 1 June 2025 until 18 April 2028.

Upon completion, Mime's debt will comprise:

·      $120 million of Super Senior bonds, attracting interest of 9.75% per annum, 4.50% of which is payable in cash and 5.25% of which is payable-in-kind in the form of additional Super Senior bonds. The maturity date of the Super Senior bonds is 17 September 2026.

·      $105 million of  "MIME02" bonds, which will attract an interest rate of 10.25% payable-in-kind. The maturity date of the MIME02 bonds is 10 November 2027.

A contingent payment of $45 million will be made to MIME02 bondholders in the event 500,000 bbl (gross) have been offloaded and sold from the Jotun FPSO by 31 December 2024. This will decline to $30 million from 1 January 2025 to 28th February 2025, to $15 million from 1 March 2025 to 31 May 2025, and to zero thereafter. If 500,000 bbl (gross) has not been offloaded and sold from the Jotun FPSO by 31 May 2025, the holders of Mime's Nordic Bonds will be allocated up to 2.4 million warrants exercisable into Kistos ordinary shares at a price of 385p each. The warrants can be exercised between 30 June 2025 and 18 April 2028. Simultaneously, up to 1.9 million of the 5.5 million warrants issued as consideration for the Mime shares will be cancelled.

The acquisition completed on 22 May 2023.

Section 8 Significant accounting policies

The Group has consistently applied the following significant accounting policies to all periods presented in these financial statements.

A             Basis of consolidation                                                         

b              Foreign currencies                                                             

c              Revenue                and other income                                              

d              Joint arrangements                                                             

e              Finance income and finance costs                                   

f               Taxation                                                                                

g              Leases                                                                                   

h              Inventory                                                                              

i               Intangible assets and goodwill                                          

j               Exploration, evaluation and production assets              

k              Commercial reserves                                                         

l               Depreciation based on depletion                                    

m             Provisions                                                                             

n              Property, plant and equipment                                        

o              Employee benefits                                                              

p              Cash and cash equivalents                                                

q              Effective interest method                                                 

r              Bond modification                                                              

s              Financial Instruments                                                         

t               Impairment                                                                          

u              Fair value                                                                              

 

a)         Basis of consolidation

(i) Business combinations

The Group accounts for business combinations using the acquisition method when the acquired set of activities and assets meets the definition of a business and control is transferred to the Group. In determining whether a particular set of activities and assets is a business, the Group assesses whether the set of assets and activities acquired includes, at a minimum, an input and substantive process, and whether the acquired set has the ability to produce outputs.

The consideration transferred in the acquisition is generally measured at fair value, as are the identifiable net assets acquired. Any goodwill that arises is tested annually for impairment. Any gain on a bargain purchase is recognised in profit or loss immediately. Transaction costs are expensed as incurred, except if related to the issue of debt or equity securities.

Any contingent consideration is measured at fair value at the date of acquisition, and discounted to present value if the consideration is expected to be settled more than 12 months from the balance sheet date. If an obligation to pay contingent consideration that meets the definition of a financial instrument is classified as equity, then it is not remeasured, and settlement is accounted for within equity. Otherwise, other contingent consideration is remeasured at fair value at each reporting date and subsequent changes in the fair value of the contingent consideration are recognised in profit or loss.

(ii) Subsidiaries

Subsidiaries are entities controlled by the Group. The Group controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. The financial statements of subsidiaries are included in the consolidated financial statements from the date on which control commences until the date on which control ceases.

(iii)          Transactions eliminated on consolidation

Intra-group balances and transactions, and any unrealised income and expenses (except for foreign currency transaction gains or losses) arising from intra-group transactions, are eliminated.

(iv)          Capital reorganisations

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

b)         Foreign currencies

Transactions in foreign currencies are translated into the respective functional currencies of Group companies at the exchange rates on the date of the transaction.

Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the exchange rate on the reporting date. Non-monetary assets and liabilities that are measured at fair value in a foreign currency are translated into the functional currency at the exchange rate when the fair value was determined. Non-monetary items that are measured based on historical cost in a foreign currency are translated at the exchange rate on the date of the transaction. Foreign currency differences are generally recognised in profit or loss and presented within finance costs.

c)         Revenue and other income

Revenue from contracts with customers is measured based on the transaction price specified in a contract with the customer, being based on quoted market prices for the gas or liquids. All revenue is measured at a point in time, being that point at which the Group meets its promise to transfer control of a quantity of gas or liquids to a customer. For gas, control is transferred once the hydrocarbons pass a specified delivery point in a pipeline. For liquids sales, control is transferred in accordance with the incoterms specified in the contract.

Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount.

d)         Joint operations

The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classified as joint operations in accordance with IFRS 11. The Group accounts for its proportionate share of the assets, liabilities, revenue and expenses of these joint operations. In addition, where the Group acts as Operator to the joint operation, the gross liabilities and receivables (including amounts due to or from non-operating partners) of the joint operation are included in the Group's balance sheet.

e)         Finance income and finance costs

Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to be prepared for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

Finance costs of debt are allocated to periods over the term of the related debt at a constant rate on the carrying amount. Arrangement fees and issue costs are deducted from the debt proceeds on initial recognition of the liability and are amortised and charged to the income statement as finance costs over the term of the debt.

Interest income or expense is recognised using the effective interest method. Dividend income is recognised in profit or loss on the date that the Group's right to receive payment is established.

f)          Taxation

Income tax expense represents the sum of the tax currently payable and deferred tax. For CIT purposes, Kistos NL1 B.V. formed a fiscal unity with its subsidiary Kistos NL2 B.V. from 1 April 2021. The companies are separately liable for tax and therefore account for their tax charge/credit on a standalone basis after taking into account the effects of horizontal compensation within the fiscal union that is applicable from 1 April 2021.

Current and deferred tax are provided at amounts expected to be paid using the tax rates and laws that have been enacted or substantively enacted by the balance sheet date.

Where the Group takes positions in tax returns in which the applicable tax regulation is subject to interpretation, it considers whether it is probable that the relevant tax authority will accept that uncertain tax treatment. The Group measures its tax liabilities based on either the most likely amount (typically if the outcomes are binary) or the expected value (if there is a range of possible values).

Current tax

Current tax comprises the expected tax payable or receivable on the taxable income or loss for the year and any adjustment to tax payable or receivable in respect of previous years. The amount of current tax payable or receivable is the best estimate of the tax amount expected to be paid or received that reflects uncertainty related to income taxes, if any. It is measured using tax rates enacted or substantively enacted at the reporting date.

Current tax assets and liabilities are offset only if certain criteria are met.

Deferred tax

Deferred tax is recognised in respect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognised for:

·      temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit or loss;

·      temporary differences related to investments in subsidiaries, associates and joint arrangements to the extent that the Group is able to control the timing of the reversal of the temporary differences and it is probable that they will not reverse in the foreseeable future; and

·      taxable temporary differences arising on the initial recognition of goodwill.

 

Deferred tax assets are recognised for unused tax losses, unused tax credits and deductible temporary differences to the extent that it is probable that future taxable profits will be available against which they can be used. Future taxable profits are determined based on the reversal of relevant taxable temporary differences. If the amount of taxable temporary differences is insufficient to recognise a deferred tax asset in full, then future taxable profits, adjusted for reversals of existing temporary differences, are considered, based on business plans for individual subsidiaries in the Group. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realised; such reductions are reversed when the probability of future taxable profits improves.

Unrecognised deferred tax assets are reassessed at each reporting date and recognised to the extent that it has become probable that future taxable profits will be available against which they can be used.

Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, using tax rates enacted or substantively enacted at the reporting date.

The measurement of deferred tax reflects the tax consequences that would follow from the manner in which the Group expects, at the reporting date, to recover or settle the carrying amount of its assets and liabilities.

Deferred tax assets and liabilities are offset only if certain criteria are met.

g)         Leases

At inception of a contract, the Group assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.

At commencement or on modification of a contract that contains a lease component, the Group allocates the consideration in the contract to each lease component on the basis of its relative stand-alone price. However, for the leases of property the Group has elected not to separate non-lease components and accounts for the lease and non-lease components as a single lease component.

The Group recognises a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received.

The right-of-use asset is subsequently depreciated using the straight-line method from the commencement date to the end of the lease term. In addition, the right-of-use asset is periodically reduced by impairment losses, if any, and adjusted for certain remeasurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Group's incremental borrowing rate. Generally, the Group uses its incremental borrowing rate as the discount rate.

The Group presents right-of-use assets within 'Property, plant and equipment' and lease liabilities in 'Other liabilities' on the balance sheet.

The Group does not recognise right-of-use assets and lease liabilities for leases of low-value assets and short-term leases (where the lease period is less than one year), including IT equipment and drilling rigs. The Group recognises the lease payments associated with these leases as an expense on a straight-line basis over the lease term, or, in the case of short-term leases of drilling rigs, capitalises the costs into intangible exploration and evaluation assets, or property plant and equipment, depending on the nature of the drilling activity.

h)         Inventory

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

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

i)          Intangible assets and goodwill

Recognition and measurement

Goodwill

Goodwill arising on the acquisition of subsidiaries and/or in a business combination is measured at cost less accumulated impairment losses.

The Group allocates goodwill to CGUs or groups of CGUs that represent the assets acquired as part of the business combination. Goodwill is tested for impairment annually (usually at 31 December) and additionally when circumstances indicate that the carrying value may be impaired.

Impairment is determined for goodwill by assessing the recoverable amount, using the value in use method, of each CGU (or group of CGUs) to which goodwill relates. When the recoverable amount of the CGU is less than its carrying amount, an impairment loss is recognised. Impairment losses relating to goodwill cannot be reversed in future periods.

j)          Exploration, evaluation and production assets

The Group adopts the successful efforts method of accounting for exploration and evaluation costs. Costs incurred before a licence is awarded or obtained are expensed in the period. All licence acquisition, exploration and evaluation costs and directly attributable administration costs are initially capitalised by well, field or exploration area, as appropriate. Interest payable is capitalised insofar as it relates to specific project financing.

These costs are written off as exploration costs in the income statement unless commercial reserves have been established or the determination process has not been completed and there are no indications of impairment.

All field development costs are capitalised as property, plant and equipment. Property, plant and equipment related to production activities are depreciated in accordance with the Group's depreciation accounting policy.

Where the Company drills a sidetrack from an original well, the costs of the original well are estimated and written off, if the well is not hydrocarbon producing.

k)         Commercial reserves

P1 developed producing and P2 reserves are estimates of the amount of oil and gas that can be economically extracted from the Group's oil and gas assets. The Group estimates its reserves using standard recognised evaluation techniques. The estimate is reviewed at least annually by management and as required by independent consultants and competent professionals.

l)          Depreciation based on unit-of-production

All expenditure carried within each field is depreciated from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field-by-field basis or by a group of fields which are reliant on common infrastructure. Costs used in the unit-of-production calculation comprise the net book value of capitalised costs incurred to date. Changes in the estimates of commercial reserves are dealt with prospectively, applied from the point in time at which management confirm the re-assessment of the appropriate reserves base.

Where there has been a change in economic conditions that indicates a possible impairment in a discovery field, the recoverability of the net book value relating to that field is assessed by comparison with the estimated discounted future cash flows based on management's expectations of future oil and gas prices and future costs.

In order to discount the future cash flows the Group calculates CGU-specific discount rates. The discount rates are based on an assessment of the Group's post-tax weighted average cost of capital (WACC).

Where there is evidence of economic interdependency between fields, such as common infrastructure, the fields are grouped as a single CGU for impairment-testing purposes.

Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the income statement, net of any amortisation that would have been charged since the impairment.

m)        Provisions

Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. The unwinding of the discount is recognised as finance cost.

Abandonment provision

An abandonment provision for decommissioning is recognised in full when the related facilities or wells are installed. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related property, plant and equipment. The amount recognised is the estimated cost of abandonment, discounted to its net present value, and is reassessed each year in accordance with local conditions and requirements. Abandonment costs expected to be incurred within 12 months of the balance sheet date (and thus classified as current liabilities) are not discounted.

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

n)         Property, plant and equipment

Recognition and measurement

Items of property, plant and equipment are measured at cost, which includes capitalised borrowing costs less accumulated depreciation and any accumulated impairment losses.

If significant parts of an item of property, plant and equipment have different useful lives, then they are accounted for as separable items (major components) of property, plant and equipment.

Any gain or loss on disposal of an item of property, plant and equipment is recognised in the profit and loss account.

Subsequent expenditure

Subsequent expenditure is capitalised only when it is probable that the future economic benefits associated with the expenditure will flow to the Group.

Depreciation

Depreciation is calculated to write-off the cost of items of property, plant and equipment less their estimated residual values using the aforementioned depreciation based on depletion accounting policy for most assets relating to oil and gas fields and straight-line method over the estimated useful lives for all other property, plant and equipment (including the Group's share in the Shetland Gas Plant, which is depreciated on a straight line basis to the estimated cessation of production date of the related gas fields).

The estimated useful lives of property, plant and equipment not relating to oil and gas fields depreciated using the straight-line method are from three to five years. Depreciation methods, useful lives and residual values are reviewed at each reporting date and adjusted if appropriate.

o)         Employee benefits including employee share-based payments

Short-term employee benefits are expensed as the related service is provided. A liability is recognised for the amount expected to be paid if the Group has a present legal or constructive obligation to pay this amount as a result of the past service provided by the employee and the obligation can be estimated reliably.

The grant-date fair value of equity-settled share-based payment arrangements granted to employees is generally recognised as an expense, with a corresponding increase in equity, over the vesting period of the awards. The amount recognised as an expense is adjusted to reflect the number of awards for which the related service and non-market performance conditions are expected to be met, such that the amount ultimately recognised is based on the number of awards that meet the related service and non-market performance conditions at the vesting date. For share-based payment awards with non-vesting conditions, the grant-date fair value of the share-based payment is measured to reflect such conditions and there is no true-up for differences between expected and actual outcomes.  

p)         Cash and cash equivalents

Cash and cash equivalents comprise cash at bank, demand deposits and other short-term highly liquid investments with original maturities of three months or less that are readily convertible to a known amount of cash and are subject to an insignificant risk of changes in value.

q)         Effective interest method

The effective interest method is a method of calculating the amortised cost of a financial asset or liability and allocating interest income or expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees on points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial asset, or, where appropriate, a shorter period.

Income is recognised on an effective interest basis for debt instruments other than those financial assets classified as at FVTPL.

r)         Bond modification

When the Group, with an existing lender, exchanges one debt instrument for another with substantially different terms, such an exchange is accounted for as an extinguishment of the original financial liability and the recognition of a new financial liability. Similarly, the Group accounts for substantial modification of the terms of an existing liability or part of it as an extinguishment of the original financial liability and the recognition of a new liability. The terms are substantially different if the discounted present fair value of the cash flows under the new terms, including any transaction costs paid and discounted using the original effective interest rate is at least 10% different from the discounted present value of the remaining cash flows of the original financial liability. If the modification is not substantial, the difference between: (i) the carrying amount of the liability including transaction costs before the modification and (ii) the present value of the cash flows after modification is recognised through the profit and loss account as a modification gain or loss.

Where debt instruments issued by the Group are repurchased, the financial liability is derecognised at the point at which cash consideration is settled. Upon derecognition, the difference between the liability's carrying amount that has been cancelled and the consideration paid is recognised as a gain or loss in the income statement.

s)         Financial instruments

Recognition and initial measurement

Financial instruments are recognised as a financial asset or financial liability when the Group becomes a party to the contractual provisions of the instrument.

A financial asset (unless it is a trade receivable without a significant financing component) or financial liability is initially measured at fair value plus, for an item not at FVTPL, transaction costs that are directly attributable to its acquisition or issue. Financial assets and liabilities are discounted to present value (with the unwinding of discount recognised in finance costs), unless the impact is not material and/or the expected settlement of the instrument is within 12 months of the balance sheet date. A trade receivable without a significant financing component is initially measured at the transaction price.

Classification and subsequent measurement

Financial assets

On initial recognition, a financial asset is classified as measured at: amortised cost; fair value through other comprehensive income (FVOCI) - debt investment; FVOCI - equity investment; or FVTPL.

When measuring the fair value of an asset or a liability, the Company uses observable market data as far as possible. Fair values are categorised into different levels in a fair value hierarchy based on the inputs used in the valuation techniques as follows: 

·      Level 1: Quoted prices (unadjusted) in active markets for identical assets or liabilities. 

·      Level 2: Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly (i.e., as prices) or indirectly (i.e., derived from prices). 

·      Level 3: Inputs for the asset or liability that are not based on observable market data (unobservable inputs). 

If the inputs used to measure the fair value of an asset or a liability fall into different levels of the fair value hierarchy, then the fair value measurement is categorised in its entirety in the same level as the lowest level input that is significant to the entire measurement. 

Financial assets are not reclassified subsequent to their initial recognition unless the Group changes its business model for managing financial assets, in which case all affected financial assets are reclassified on the first day of the first reporting period following the change in the business model.

A financial asset is measured at amortised cost if it meets both of the following conditions and is not designated as at FVTPL:

·      it is held within a business model whose objective is to hold assets to collect contractual cash flows; and

·      its contractual terms give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

All financial assets not classified as measured at amortised cost or FVOCI as described above are measured at FVTPL. This includes all derivative financial assets. On initial recognition, the Group may irrevocably designate a financial asset that otherwise meets the requirements to be measured at amortised cost or at FVOCI as at FVTPL if doing so eliminates or significantly reduces an accounting mismatch that would otherwise arise.

Financial assets - subsequent measurement and gains and losses

·      Financial assets at FVTPL - These assets are subsequently measured at fair value. Net gains and losses, including any interest or dividend income, are recognised in profit or loss.

·      Financial assets at amortised cost - These assets are subsequently measured at amortised cost using the effective interest method. The amortised cost is reduced by impairment losses. Interest income, foreign exchange gains and losses and impairment are recognised in profit or loss. Any gain or loss on derecognition is recognised in profit or loss.

Financial liabilities - classification, subsequent measurement and gains and losses

Financial liabilities are classified as measured at amortised cost or FVTPL. A financial liability is classified as at FVTPL if it is classified as held-for-trading, it is a derivative or it is designated as such on initial recognition. Financial liabilities at FVTPL are measured at fair value and net gains and losses, including any interest expense, are recognised in profit or loss. Other financial liabilities are subsequently measured at amortised cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognised in profit or loss. Any gain or loss on derecognition is also recognised in profit or loss.

Derecognition

Financial assets

The Group derecognises a financial asset when:

·      the contractual rights to the cash flows from the financial asset expire; or

·      it transfers the rights to receive the contractual cash flows in a transaction in which either:

o  substantially all of the risks and rewards of ownership of the financial asset are transferred; or

o  the Group neither transfers nor retains substantially all of the risks and rewards of ownership and it does not retain control of the financial asset.

The Group enters into transactions whereby it transfers assets recognised in its balance sheet but retains either all or substantially all of the risks and rewards of the transferred assets. In these cases, the transferred assets are not derecognised.

Financial liabilities

The Group derecognises a financial liability when its contractual obligations are discharged or cancelled or expire. The Group also derecognises a financial liability when its terms are modified and the cash flows of the modified liability are substantially different, in which case a new financial liability based on the modified terms is recognised at fair value, and if the Group repurchases a debt instrument it previously issued.

On derecognition of a financial liability, the difference between the carrying amount extinguished and the consideration paid (including any non-cash assets transferred or liabilities assumed) is recognised in the profit and loss account. If only part of a financial liability is derecognised, the previous carrying amount of the financial liability is allocated between the part that continues to be recognised and the part that is derecognised based on the relative fair values of those parts on the date of the repurchase, with the difference between the carrying amount allocated to the part derecognised and the consideration paid recognised within finance costs. 

Share capital - ordinary shares

Incremental costs directly attributable to the issue of ordinary shares, net of any tax effects, are recognised as a deduction from equity. Income tax relating to transaction costs of an equity transaction is accounted for in accordance with IAS12.

Derivative financial instruments and hedge accounting

From time to time, the Group holds derivative financial instruments to hedge cash flow risk exposures. Embedded derivatives are separated from the host contract and accounted for separately if the host contract is not a financial asset and certain criteria are met.

Derivatives are initially measured at fair value. Subsequent to initial recognition, derivatives are measured at fair value, and changes therein are generally recognised in profit or loss.

The Group designates (i) certain derivatives as hedging instruments to hedge the variability in cash flows associated with highly probable forecast transactions arising from changes in commodity prices and (ii) certain derivatives and non-derivative financial liabilities as hedges of currency risk on a net investment in a foreign operation.

At inception of designated hedging relationships, the Group documents the risk management objective and strategy for undertaking the hedge. The Group also documents the economic relationship between the hedged item and the hedging instrument, including whether the changes in cash flows of the hedged item and hedging instrument are expected to offset each other.

Cash flow hedge 

When a derivative is designated as a cash flow hedging instrument, the effective portion of changes in the fair value of the derivative is recognised in OCI and accumulated in the hedging reserve. The effective portion of changes in the fair value of the derivative that is recognised in OCI is limited to the cumulative change in fair value of the hedged item, determined on a present value basis, from inception of the hedge. Any ineffective portion of changes in the fair value of the derivative is recognised immediately in profit or loss.

The Group designates only the change in fair value of the spot element of forward exchange contracts as the hedging instrument in cash flow hedging relationships. The change in fair value of the forward element of forward exchange contracts (forward points) is separately accounted for as a cost of hedging and recognised in a costs of hedging reserve within equity.

For all other hedged forecast transactions, the amount accumulated in the hedging reserve and the cost of hedging reserve is reclassified to profit or loss in the same period or periods during which the hedged expected future cash flows affect profit or loss.          

If the hedge no longer meets the criteria for hedge accounting or the hedging instrument is sold, expires, is terminated or is exercised, then hedge accounting is discontinued prospectively. When hedge accounting for cash flow hedges is discontinued, the amount that has been accumulated in the hedging reserve remains in equity until, for a hedge of a transaction resulting in the recognition of a non-financial item, it is included in the non-financial item's cost on its initial recognition or, for other cash flow hedges, it is reclassified to profit or loss in the same period or periods as the hedged expected future cash flows affect profit or loss.

If the hedged future cash flows are no longer expected to occur, then the amounts that have been accumulated in the hedging reserve and the cost of hedging reserve are immediately reclassified to profit or loss.

t)          Impairment

Non-derivative financial assets

The Group recognises loss allowances for expected credit losses (ECLs) on financial assets measured at amortised cost.

The Group measures loss allowances at an amount equal to lifetime ECLs, except for the following, which are measured at 12-month ECLs:

·      debt securities that are determined to have low credit risk at the reporting date; and

·      other debt securities and bank balances for which credit risk (i.e., the risk of default occurring over the expected life of the financial instrument) has not increased significantly since initial recognition.

Loss allowances for trade receivables and contract assets are always measured at an amount equal to lifetime ECLs.

When determining whether the credit risk of a financial asset has increased significantly since initial recognition and when estimating ECLs, the Group considers reasonable and supportable information that is relevant and available without undue cost or effort. This includes both quantitative and qualitative information and analysis, based on the Group's historical experience and informed credit assessment and including forward-looking information.

The Group assumes that the credit risk on a financial asset has increased significantly if it is more than 30 days past due.

The Group considers a financial asset to be in default when:

·      the borrower is unlikely to pay its credit obligations to the Group in full, without recourse by the Group to actions such as realising security (if any is held); or

·      the financial asset is more than 90 days past due.

The Group considers a debt security to have low credit risk when its credit risk rating is equivalent to the globally understood definition of investment grade.

Lifetime ECLs are the ECLs that result from all possible default events over the expected life of a financial instrument. Twelve-month ECLs are the portion of ECLs that result from default events that are possible within the 12 months after the reporting date (or a shorter period if the expected life of the instrument is less than 12 months).

The maximum period considered when estimating ECLs is the maximum contractual period over which the Group is exposed to credit risk.

Measurement of ECLs

ECLs are a probability-weighted estimate of credit losses. Credit losses are measured as the present value of all cash shortfalls (i.e., the difference between the cash flows due to the entity in accordance with the contract and the cash flows that the Group expects to receive). ECLs are discounted at the effective interest rate of the financial asset.

Credit-impaired financial assets

At each reporting date, the Group assesses whether financial assets carried at amortised cost and debt securities at FVOCI are credit-impaired. A financial asset is credit-impaired when one or more events that have a detrimental impact on the estimated future cash flows of the financial asset have occurred.

Evidence that a financial asset is credit-impaired includes the following observable data:

·      significant financial difficulty of the borrower or issuer;

·      a breach of contract such as a default or being more than 90 days past due;

·      the restructuring of a loan or advance by the Group on terms that the Group would not consider otherwise;

·      it is probable that the borrower will enter bankruptcy or another financial reorganisation; or

·      the disappearance of an active market for a security because of financial difficulties.

Loss allowances for financial assets measured at amortised cost are deducted from the gross carrying amount of the assets.

For debt securities at FVOCI, the loss allowance is charged to profit or loss and is recognised in OCI.

Write-off

The gross carrying amount of a financial asset is written off when the Group has no reasonable expectations of recovering a financial asset in its entirety or a portion thereof. For individual customers, the Group has a policy of writing off the gross carrying amount when the financial asset is 180 days past due based on historical experience of recoveries of similar assets. For corporate customers, the Group individually makes an assessment with respect to the timing and amount of write-off based on whether there is a reasonable expectation of recovery. The Group expects no significant recovery from the amount written off. However, financial assets that are written off could still be subject to enforcement activities in order to comply with the Group's procedures for recovery of amounts due.

Non-financial assets

At each reporting date, the Group reviews the carrying amounts of its non-financial assets to determine whether there is any indication of impairment. If any such indication exists, then the asset's recoverable amount is estimated. Goodwill is tested annually for impairment.

For impairment testing, assets are grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or CGUs. Goodwill arising from a business combination is allocated to CGUs or groups of CGUs that are expected to benefit from the synergies of the combination.

The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. Value in use is based on the estimated future cash flows, discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset or CGU.

An impairment loss is recognised if the carrying amount of an asset or CGU exceeds its recoverable amount.

Impairment losses are recognised in profit or loss. They are allocated first to reduce the carrying amount of any goodwill allocated to the CGU, and then to reduce the carrying amounts of the other assets in the CGU on a pro rata basis.

An impairment loss in respect of goodwill is not reversed. For other assets, an impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortisation, if no impairment loss had been recognised.

u)         Fair value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date in the principal or, in its absence, the most advantageous market to which the Group has access at that date. The fair value of a liability reflects its non-performance risk.

A number of the Group's accounting policies and disclosures require the measurement of fair values, for both financial and non-financial assets and liabilities.

When one is available, the Group measures the fair value of an instrument using the quoted price in an active market for that instrument. A market is regarded as active if transactions for the asset or liability take place with sufficient frequency and volume to provide pricing information on an ongoing basis.

If there is no quoted price in an active market, then the Group uses valuation techniques that maximise the use of relevant observable inputs and minimise the use of unobservable inputs. The chosen valuation technique incorporates all of the factors that market participants would take into account in pricing a transaction.

If an asset or a liability measured at fair value has a bid price and an ask price, then the Group measures assets and long positions at a bid price and liabilities and short positions at an ask price.

The best evidence of the fair value of a financial instrument on initial recognition is normally the transaction price - i.e., the fair value of the consideration given or received. If the Group determines that the fair value on initial recognition differs from the transaction price and the fair value is neither evidenced by a quoted price in an active market for an identical asset or liability nor based on a valuation technique for which any unobservable inputs are judged to be insignificant in relation to the measurement, then the financial instrument is initially measured at fair value, adjusted to defer the difference between the fair value on initial recognition and the transaction price. Subsequently, that difference is recognised in profit or loss on an appropriate basis over the life of the instrument but no later than when the valuation is wholly supported by observable market data, or the transaction is closed out.

 

Appendix A: Glossary

 

2C	Best estimate of contingent resources
2P	Proved plus probable reserves
Adjusted EBITDA	EBITDA, excluding the effects of significant one-off and/or non-cash items of income and expenditure which may have, in the opinion of management, an impact on the quality of earnings. Adjusted EBITDA excludes development expenses, share-based payment expenses, transaction costs and movements in contingent consideration payable.
AFE	Authority For Expenditure
Average realised gas price	Calculated as revenue from gas production divided by units of gas sold for the period. Units of gas sold in a period may be different to units of gas produced in a period.
bbl	Barrel of oil
boe	Barrels of oil equivalent
boepd	Barrels of oil equivalent produced per day
cijns	A royalty tax levied on oil and gas sales in the Netherlands. Historically set a 0% in respect of gas produced offshore; but for 2023 and 2024 temporarily increasing to a rate of 65% on turnover in excess of €0.5 per cubic metre of gas sold.
CIT	Dutch Corporate Income Tax
Company	Kistos Holdings plc
DEI	Diversity, equality and inclusion
DSA	Decommissioning Security Agreement
EBITDA	Earnings (operating profit) before interest, tax, depreciation, impairment and amortisation
EBN	Energie Beheer Nederland
EIR	Effective interest rate
EPL	Energy Profits Levy
FID	Final Investment Decision
FPSO	Floating production storage and offloading vessel
G&A	General and administrative expenditure
GLA	Greater Laggan Area
GLA acquisition	The acquisition by the Group of a 20% working interest in the GLA licences, producing gas fields and associated infrastructure alongside various interests in certain other exploration licences, including a 25% interest in the Benriach prospect, from TotalEnergies E&P UK Limited.
Group	Kistos Holdings plc including its subsidiaries
JV	Joint venture
Kistos group	Kistos Holdings plc including its subsidiaries
LNG	Liquefied natural gas
Mime	Mime Petroleum A.S.
MMBtu	Million British Thermal units
MWh	Megawatt hour
MWhe	Megawatt hour equivalent
Net debt/net cash	Cash and cash equivalents less face value of Nordic Bonds outstanding. Management's definition of net debt is different to that defined in the leverage ratio calculation in respect of the Group's borrowings (as calculated in note 5.1.2).
NGL	Natural gas liquids
NSTA	North Sea Transition Authority
OCI	Other comprehensive income
P50 estimate	50th percentile estimate, equivalent to 2P
SGP	Shetland Gas Plant
SodM	State Supervisor of Mines
Solidarity Contribution Tax	A tax levied by the Dutch government, following the adoption of Council Regulation (EU) 1854/2022, which required EU member states to introduce a 'solidarity contribution' for companies active in the oil, gas, coal and refinery sectors. The Dutch implementation of this solidarity contribution has been legislated by a retrospective 33% tax on 'excess profit' realised during 2022, with 'excess profit' defined as that profit exceeding 120% of the average profit of the four previous financial years. Companies in scope are those realising at least 75% of their turnover through the production of oil and natural gas, mining activities, refining of petroleum or coke oven products.
SPS	Dutch State Profit Share tax
TotalEnergies	TotalEnergies E&P Limited
Unit opex	Calculated as cash production costs divided by production (see appendix B).

 

 

Appendix B Non-IFRS Measures

B1 Pro forma information

Pro forma information shows the impact to certain results of the Group as if the GLA acquisition had completed on 1 January 2022, and as if the Tulip Oil acquisition had completed on 1 January 2021. Management believe pro forma information is useful as it allows meaningful comparison of full year results across periods.

	Revenue	Adjusted EBITDA	EBITDA
Period ended 31 December 2021:
As reported	89,628	78,861	71,541
Pro forma period adjustments	27,103	24,001	24,001
Pro forma	116,731	102,862	95,542
Period ended 31 December 2022:
As reported	411,512	380,015	404,037
Pro forma period adjustments	156,933	137,187	137,187
Pro forma	568,445	517,202	541,224

 

B2 Net debt

Net debt is a measure which management believe is useful as it provides an indicator of the Group's overall liquidity. It is defined as cash and cash equivalents less the face value of outstanding bond debt. A positive figure represents net cash and a negative figure represents a net debt position. The difference between management's definition of net debt and net debt for the purposes of the leverage ratio calculation is reconciled below.

€'000	Note	31 December 2022	31 December 2021
Cash and cash equivalents	4.1	211,980	77,266
Face value of bond debt	5.1	(81,572)	(150,000)
Net cash/(debt)		130,408	(72,734)
Difference between carrying value and face value of bond debt	5.1	(1,134)	1,958
Lease liabilities	4.4	(1,211)	(91)
Net cash/(debt) for leverage ratio	5.1.2	128,063	(70,867)

 

B3 Unit opex

Unit opex is defined as total production (converted to MWh equivalent using the conversion factors in Appendix C) divided by adjusted operating costs. Adjusted operating costs are operating costs per the income statement less accounting movements in inventory, which are primarily those operating costs capitalised into liquids inventory. Such costs are only recognised in the income statement upon sale of the related product (rather than as incurred).

€'000		Year ended 31 December 2022	Period ended 31 December 2021
Operating costs		22,927	6,143
Accounting movements in inventory		4,135	(35)
Adjusted operating costs		27,062	6,108
Pro forma period adjustment		19,706	3,649
Pro forma adjusted operating costs		46,768	9,757
Total production (thousand MWh)		4,642	1,661
Pro forma period adjustment (thousand MWh)		2,098	1,418
Total pro forma production (thousand MWh)		6,740	3,079
Unit opex (€/MWh)		5.8	3.7
Pro forma unit opex (€/MWh)		6.9	3.2

 

 

Appendix C Conversion Factors

37.3 scf in 1 Nm³

1.7 MWh in 1 boe

34.12 therms in 1 MWh