TIDMKIST
RNS Number : 8990A
Kistos Holdings PLC
30 May 2023
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 EUR517.2 million (2021: EUR102.9
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 2021 (actual) 2021 (pro
forma)(1) forma)(1)
--------------------------- ---------- --------------- ------------ --------------- ------------
Gas production(2) MM Nm(3) 391 556 145 268
Total production rate(3) Boe/d 10,600 10,900 4,300 5,000
Revenue EUR'000 411,512 568,445 89,628 116,731
Average realised gas
price(2) EUR/MWh 98.7 93.8 57.4 39.8
Unit opex(4) EUR/MWh 5.8 6.9 3.7 3.2
Adjusted EBITDA(4) EUR'000 380,015 517,202 78,861 102,862
Statutory profit/(loss)
before tax EUR'000 254,125 n/a(5) (73,857) (65,940)
Effective tax rate % 89.8% n/a(5) 45.7% n/a(5)
Closing cash EUR'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 EUR73 million, including EUR44 million of
impairment charges relating to exploration assets in the
Netherlands, EUR27 million of gains from changes and releases in
acquisition contingent consideration balances, and a total tax
charge of EUR228 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 EUR212 million (31
December 2021: EUR77 million) and net cash of EUR130 million (31
December 2021: net debt of EUR73 million).
-- Retired 46% of outstanding debt by repurchasing EUR68 million
of Nordic Bonds, leaving EUR82 million outstanding.
-- Capital expenditure on a cash basis, excluding business acquisitions, was EUR19.5 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 CO(2) 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 via Hawthorn Advisors
Andrew Austin
Panmure Gordon (NOMAD, Joint Broker) Tel: 0207 886 2500
John Prior / James Sinclair-Ford
Berenberg (Joint Broker) Tel: 0203 207 7800
Matthew Armitt / Ciaran Walsh
Hawthorn Advisors (Public Relations Tel: 0203 745 4960
Advisor)
Henry Lerwill / Simon Woods
Camarco (Public Relations Advisor) Tel: 0203 757 4983
Billy Clegg
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 EUR250 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 CO(2) emissions of less than
0.01 kg per boe (excluding necessary flaring during drilling
campaigns). CO(2) 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 EUR46.9 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 EUR380.0 million (2021: EUR78.9
million) while adjusted pro forma EBITDA, which includes a full
12-month contribution from the GLA, was EUR517.2 million (2021:
EUR102.9 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 EUR130.4 million (2021: net debt of EUR72.7
million), which was achieved after paying for the GLA acquisition
and cash capital expenditure of EUR19.5 million (2021: EUR20.0
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 Nm(3) per day (net to Kistos)
compared with 0.73 million Nm(3) 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 Nm(3) 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 CO(2)
e/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 CO(2) 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.EUR18 million pre-tax or c.EUR3 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 24km(2) 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 EUR7.5 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
km(2) 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 CO(2) 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 31 December 31 December 31 December
2022 2022 (pro 2021 2021
forma)(1)
(actual) (actual) (pro forma)(1)
========= ============= ============= ============= =================
Revenue EUR'000 411,512 568,445 89,628 116,731
===================== ========= ============= ============= ============= =================
Average realised
gas price EUR/MWh 98.7 93.8 57.4 39.8
===================== ========= ============= ============= ============= =================
Unit opex(2) EUR/MWh 5.8 6.9 3.7 3.2
===================== ========= ============= ============= ============= =================
Adjusted EBITDA(2) EUR'000 380,015 517,202 78,861 102,862
===================== ========= ============= ============= ============= =================
Profit before
tax EUR'000 254,125 n/a (3) (73,857) (65,940)
===================== ========= ============= ============= ============= =================
Earnings/(loss)
per share EUR 0.31 n/a (3) (0.68) n/a (3)
===================== ========= ============= ============= ============= =================
Operating cashflow EUR'000 290,473 n/a (3) 47,956 n/a (3)
===================== ========= ============= ============= ============= =================
Cash capital
expenditure EUR'000 19,454 n/a(3) 19,958 n/a(3)
===================== ========= ============= ============= ============= =================
Closing cash EUR'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
Nm(3) (10.6 kboe/d total hydrocarbon production) in the year to 31
December 2022 (2021: 145 million Nm(3) 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 Nm(3) (5.0 kboe/d total
hydrocarbon production) to 556 million Nm(3) or (10.9 kboe/d total
hydrocarbon production).
The Group's average realised gas price during the period was
EUR98.7/MWh versus EUR57.4/MWh in 2021 and this, combined with
higher production, resulted in total revenue from gas sales
increasing by 459% year-on-year to EUR411.5 million. This includes
the impact of the hedging programme in the Netherlands which ended
in March 2022, whereby 300,000 MWh was hedged at EUR25/MWh. On a
pro forma basis, these figures were EUR93.8/MWh and EUR568.4
million. Revenue from natural gas liquids (NGL) and crude oil sales
was EURnil but EUR10.7 million on a pro forma basis, reflecting the
timing of liftings in the periods. This compared with EUR0.1
million and EUR0.6 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 EUR3.7 per MWh in 2021 to EUR5.8
per MWh in 2022. On a pro forma basis, there was a more pronounced
increase from EUR3.2 per MWh in 2021 to EUR6.9 per MWh in 2022
reflecting a full year of higher GLA operating costs.
During 2022, Kistos incurred pre -- FID development expenses of
EUR1.8 million (2021, EUR4.5 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
EUR'000 Year ended Period ended
31 December 2022 31 December 2021
=================== ===================
Pro forma(1) Adjusted
EBITDA 517,202 102,862
================================ =================== ===================
Pro forma(1) 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 26,993 -
movements
-------------------------------- ------------------- -------------------
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 EUR380.0 million or EUR81.9 per MWh
equivalent of production in 2022. Both figures were substantially
ahead of the comparable figures for the period to 31 December 2021
of EUR78.9 million and EUR47.5 per MWh equivalent respectively,
primarily driven by the material increase in commodity prices
during the period. On a pro forma basis, Adjusted EBITDA was
EUR517.2 million or EUR76.7 per MWh equivalent of production versus
EUR102.9 million or EUR33.4 per MWh equivalent in 2021.
The impairments primarily relate to the Q11-B and Q10-B assets
(EUR36.8 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 EUR7.5 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 EUR7.5 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
EUR19.5 million (2021 EUR20.0 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
EUR40-45 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 EUR276.3 million (2021:
operating loss of EUR62.8 million) and a profit before tax of
EUR254.1 million (2021: loss before tax of EUR73.9 million). This
figure was after impairments of EUR44.5 million (2021: EUR121.0
million), and net finance costs of EUR22.1 million (2021: EUR11.1
million), including interest charges of EUR10.5 million associated
with Kistos NL2's Nordic Bonds and a non-cash loss on redemption of
EUR6.4 million relating to repurchases of EUR68.4 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
EUR212.0 million (31 December 2021, EUR77.3 million) and net cash
of EUR130.4 million (31 December 2021, net debt of EUR72.7
million). The increase in net cash of over EUR200 million was
achieved after capital expenditure and acquisition cash outflows of
EUR67.0 million and bond repurchases of EUR71.8 million, and
reflected a 605% increase year-on-year in operating cash flow from
EUR48.0 million to EUR290.5 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 EUR65.7 million
in cash taxes in 2022 (2021, EUR0.9 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 EUR15.0 million at the
end of 2021 to EUR143.1 million at the end of 2022. This includes
EUR46.9 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
EUR'000 Year ended Period ended
31 December 31 December
2022 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 CO(2) e/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 CO(2) e/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 CO(2) e/boe and 14.1 kg CO(2) e/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 CO(2) 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
CO(2) emissions. Similarly, the Company estimates that its policy
of conducting offshore visits via boat rather than helicopter saved
more than 21 tonnes of CO(2) emissions. We continue to reduce CO(2)
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 Mitigation Change
ownership
=============== ==================================== ==============
Strategic
===================================== =============== ==================================== ==============
Political risk Peter Mann Directly and through Risk has
There are risks that CEO Element NL, OEUK, BRINDEX increased
changes in national and other industry associations,
government policies the Group engages with
towards oil and gas-focused the respective governments
companies adversely and other appropriate
impact the ability organisations to ensure
of the Group to deliver the Group is kept abreast
its strategy. This of expected potential
could result in challenges, changes and takes an
delays and refusals active role in making
related to permitting appropriate representations.
applications for development,
appraisal and exploratory
drilling in Kistos-owned
or targeted blocks.
===================================== =============== ==================================== ==============
Growth of reserves Andrew Austin The Group identifies No change
base Executive and evaluates a broad in risk
The Group's growth Chairman range of acquisitions
strategy is dependent and similar opportunities
on identifying new and maintains strong
reserves and resources, relationships within
and does so through the industry. Potential
development and acquisition. opportunities are evaluated
Organic growth is internally and with
focused on developing support from subject
existing resources matter experts where
into producible reserves. appropriate. A rigorous
As part of this growth assessment process evaluates
strategy, there is and determines the risks
a risk that the Group associated with all
may fail to identify potential business acquisitions
attractive acquisition and strategic alliances,
opportunities or select including conducting
inappropriate exploration stress-test scenarios
work programmes. for sensitivity analysis.
Exploration drilling If applicable, each
may deliver adverse assessment includes
results due to factors an analysis of the Group's
including poor quality ability to operate in
(or misinterpretation a new jurisdiction.
of) data, failure/underperformance Exploration, appraisal
of offshore vessels and development cases
or other crucial equipment, are robustly assessed
unforeseen problems and stress tested against
occurring during drilling cost, price and taxation
and delays to offshore sensitivities.
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.
===================================== =============== ==================================== ==============
Climate change Peter Mann The Board actively reviews No change
Changes in laws, regulations, CEO the Group's strategy in risk
policies, obligations towards energy transition
and social attitudes with an aim to provide
relating to the transition long -- term returns
to a lower carbon to shareholders, and
economy could lead regularly considers
to higher costs, or the impact of climate
reduced demand and change and potential
prices for gas, impacting changes to policy in
the profitability its decision making.
of the Group. Sources It continues to investigate
of debt and equity and implement actions
finance may become on its existing assets
more expensive or that could reduce its
restricted as investors environmental footprint,
diversify away from and environmental considerations
oil and gas-based are a key factor in
investments. 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.
===================================== =============== ==================================== ==============
Cyber security Richard The Group outsources No change
Breaches in, or failures Slape its provision of IT in risk
of, the Group's information CFO equipment and help-desk
security management services to third parties.
could adversely impact Various network management
its business activities. systems are used to
The Group's information protect the Group's
security management IT environment.
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.
===================================== =============== ==================================== ==============
Joint venture As a Peter Mann The Group has representatives New risk
minority non-operating CEO on all of the joint
partner in the GLA ventures' committees
partnership, the interests (including operating,
and objectives of finance and technical)
the partners may not and regularly engages
be aligned. This may with the joint-venture
result in longer decision operator and other participants
making processes, in the joint venture
programmes approved with regards to key
which are not in line decision and strategic
with the Group's strategy direction.
and/or investment
cases which the Group
believes are in its
best interests not
voted through by partners.
===================================== =============== ==================================== ==============
Operational
===================================== =============== ==================================== ==============
HSE and compliance Peter Mann The Group works closely Increase
The Group is exposed CEO with regulators to ensure in risk
to various risks in that all required planning
relation to HSE, compliance, consents and permits
planning, environmental, for operations are in
regulatory, licensing place and maintains
and other permitting continual dialogue with
rules associated primarily all stakeholders to
with production operations, understand emerging
drilling and construction. requirements.
A loss of hydrocarbon All activities are conducted
containment, in addition in accordance with Board-approved
to causing harm to policies, standards
the environment, could and procedures. The
result in reputational Group requires adherence
damage and incur financial to its Code of Conduct
penalties. 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.
===================================== =============== ==================================== ==============
Hydrocarbon production Peter Mann The Group continuously Decrease
and operational performance CEO reviews production performance in risk
The Group's production from each of its wells
volumes (and therefore to enable it to predict
revenue) are dependent well performance and
on the operational plan well-intervention
performance of its activities as needed.
producing assets. To the extent possible
The Group's producing discussions are held
assets are subject with third parties to
to operational risks, manage shutdowns both
including no critical planned and unplanned.
spare equipment or Planned and unplanned
plant availability downtime assumptions
during the required are built into the corporate
plant maintenance budgeting cycle and
or shutdowns; asset cash flow projections.
integrity and health, Following acquisition
safety, security and of interests in the
environment incidents; producing GLA assets,
and low reserves recovery the Group's production
from the field and base is diversified
exposure to natural and thus is no longer
hazards such as extreme exposed to a single
weather events. source of revenue.
===================================== =============== ==================================== ==============
Project delivery Peter Mann Each project has a clear Increase
Risk of delays in CEO project delivery framework in risk
project delivery and with a responsible project
higher costs being lead. Delivery against
incurred, especially the project objectives,
under the current timeline and cost are
high inflationary regularly monitored.
environment. 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.
===================================== =============== ==================================== ============
Retention of key personnel Peter Mann The Board seeks to cultivate No change
The Group may not CEO a safe, respectful working in risk
be able to retain environment where people
key personnel, and can thrive. Management
there can be no assurance has undertaken a benchmarking
that the Group will exercise on salaries
be able to continue to ensure that acquired
to attract and retain staff are retained through
all personnel suitably a strong remuneration
qualified and competent culture. Workplace surveys
necessary for the are undertaken to ascertain
safe and efficient morale and employee
operation and development concerns and allow management
of its business. to swiftly address any
issues. A long-term
share incentive plan
is now in place for
key staff in the UK
and the Netherlands.
===================================== =============== ==================================== ============
Financial
===================================== =============== ==================================== ============
Commodity price risk Richard The Board continuously No change
The Group's cashflow Slape reviews the oil and in risk
and results are heavily CFO gas markets to determine
dependent on natural whether future hedges
gas and other commodity are needed and has the
prices, which are necessary contracts
dependent on several in place to undertake
factors including hedging activities if
the impact of climate required.
change concerns, geopolitics Cash flow projections
(including events and liquidity analyses
such as the Russia-Ukraine are regularly tested
conflict) and regulatory for downside price scenarios.
developments.
===================================== =============== ==================================== ============
Liquidity risk Richard Management regularly No change
Adverse changes to Slape reviews the Group's in risk
production, commodity CFO cash forecasts and its
prices, taxation and covenants to ensure
surety bond requirements an adequate headroom
may put pressure on of cash availability.
the Group's available The Group is in regular
liquidity, constraining dialogue with potential
its options to grow providers of finance
the business or, in and surety bond providers.
the worst cases, cause
it to breach its bond
covenants or become
insolvent.
===================================== =============== ==================================== ============
Decommissioning costs Richard The Group mitigates No change
and timing Slape this risk through in-house in risk
The future costs and CFO decommissioning experience,
timing of decommissioning coupled with a continued
is a significant estimate; focus on delivering
any adverse movement asset value to defer
in price, operational abandonment liabilities.
issues and changes Decommissioning security
in reserves and resource arrangements and postings
estimates could have in place for UK assets
a significant impact which mitigate risk
on the cost and timing from a regulatory and
of decommissioning. joint-venture partner
Where decommissioning perspective.
costs are to be shared The Group maintains
as part of a joint strong relationships
venture, risk of partners with surety bond providers
not fulfilling their and have obtained comfort
commitments leaving that the surety market
remaining partners can continue to provide
exposed. Changes to security for the expected
commodity prices, DSA provisions.
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.
===================================== =============== ==================================== ============
Taxation Richard The Group engages with New risk
Longer-term additional Slape various industry bodies
and increased taxes CFO to raise concerns and
imposed on oil and suggest alternative
gas companies by governments approaches to proposed
in reaction to so-called taxation policies. Projects
'windfall profits' and liquidity projections
arising from short-term are modelled with various
movements in commodity tax sensitivities in
prices have led to place.
a higher tax burden. The Group engages the
Uncertainty over tax support and advice of
regimes may also hinder external experts and
future investment legal counsel on taxation
decisions and reduce matters for areas where
the returns from, there exists significant
and profitability uncertainty and judgement.
of, operations. The Group will review
Should the Dutch tax its investment strategy
office rule unfavourably and may decide not to
against the Group invest further in, or
with regards to the consider withdrawing
Solidarity Contribution from, jurisdictions
Tax, this would have with a recent history
a material impact of significant tax changes,
to the Group's projected implementation of retrospective
cash position. taxation, or where the
taxation regime proves
too burdensome.
===================================== =============== ==================================== ============
Consolidated Financial Statements
Consolidated income statement
EUR'000 Note Year ended 14 October
31 December 2020 to 31
2022 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 26,993
consideration 2.10.2 -
-------------------------------------------------- -------- -------------- ----------------
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 (EUR) 3.1 0.31 (0.68)
Diluted earnings/(loss) per share (EUR) 3.1 0.31 (0.68)
-------------------------------------------------- -------- -------------- ----------------
Consolidated statement of other comprehensive income
EUR'000 Note Year ended 14 October 2020
31 December to 31 December
2022 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
EUR'000 Note 31 December 31 December
2022 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
EUR'000 Note Share Share Merger Capital Hedge Translation Retained Share-based Total
capital premium reserve reorganisation reserve reserve earnings payment equity
reserve reserve
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
EUR'000 Note Year ended 14 October
31 December 2020 to 31
2022 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 EUR268 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 EUR47 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 EUR27.4 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, EUR223.6 million of fixed assets, EUR115.0
million of decommissioning liabilities and EUR10.9 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 EUR44.3 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 EUR27.0 million recognised in the income statement
relating changes in contingent consideration payable (note 2.10.2
), comprising a EUR19.5 million fair value gain relating to
actualisation of the GLA acquisition payment linked to gas price,
and a release of EUR7.5 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 EUR71.6 million arising from the introduction
of the Energy Profits Levy (EPL) in the UK (note 6.2 );
-- A tax charge of EUR46.9 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 EUR50 million, a reduction to share premium of EUR35
million and a reduction to the merger reserve of EUR14 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 EUR141.7 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
Critical judgements and key sources of estimation uncertainty
applicable to this section as a whole
Key source of estimation uncertainty - estimation of reserves
and contingent resources
Reserves and contingent resources are those hydrocarbons that
can be economically extracted from the Group's licence interests.
The Group's reserves and contingent resources have been estimated
based on information compiled by independent qualified persons, as
updated and refined by the Group's internal experts and external
contractors. These estimates use standard recognised evaluation
techniques and include geological and reservoir information (as
updated from data obtained through operation of a field), capital
expenditure, operating costs and decommissioning estimates. These
inputs are validated where possible against analogue reservoirs,
and actual historical reservoir and production performance.
Changes to reserves estimates may significantly impact the
financial position and performance of the Group. This could include
a significant change in the depreciation charge for fixed assets,
abandonment provisions, the results of any impairment testing
performed and the recognition and carrying value of any deferred
tax assets. During the period, the Group re-assessed the reserves
for the Q10-A field following changes to royalty taxes, a decision
not to proceed with an alternative export route and revised
understanding of the reservoirs. The revised assessment was
approved and made effective during Q3 2022, with the reserves used
in the revised unit-of-production calculation being only that
quantity of hydrocarbons the wells in their condition at the time
were estimated to be able to access i.e. a no further activity
case. Management estimate that the field contains a higher level of
hydrocarbon reserves than that used in the unit-of-production
depletion calculation which can be accessed with successful
developments including further well interventions, stimulation,
sidetrack and infill wells.
2.1 Revenue
EUR'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.
EUR'000 Note Year ended 14 October
31 December 2022 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 2.10.2 26,993 -
releases of contingent consideration
---------------------------------------- -------- ------------------- ----------------
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
Significant judgement - inter-segment revenue
For the purposes of segmental reporting, the Netherlands segment
has reported within revenue the net margin recognised from gas
purchased from the UK segment sold on to third parties. The
assessment of whether the Dutch entity in the arrangement is acting
as principal or agent (and thus recognises revenue from the
arrangement on a gross or net basis) is a significant judgement and
has been based on the indicators in IFRS 15, an assessment of
control, the terms and conditions of the relevant contracts, and
other indicators providing persuasive evidence. Management's
conclusion on this judgement has no impact on the total
consolidated revenue presented in the income statement, but impacts
on its conclusion over the applicability of the Solidarity
Contribution Tax (note 6.3 ).
EUR'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.
EUR'000 Year ended 31 December 14 October 2020 to
2022 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, CO(2) 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
Source of estimation uncertainty - estimate of abandonment
provisions
Decommissioning costs are uncertain and cost estimates can vary
in response to many factors, including changes to the relevant
legal requirements, the expected cessation of production date of
the related asset, the emergence of new technology or experiences
at other assets. The expected timing, work scope, amount of
expenditure and risk weighting may also change. Therefore,
significant estimates and assumptions are made in determining the
abandonment provision balance. The estimated decommissioning costs,
and inflation and discount rates applied to derive the amounts
recognised on the balance sheet, are reviewed at least annually,
and the results of this review are then assessed alongside
estimates from operators (where the Group is a non-operating
partner in an arrangement).
EUR'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 EUR27.4 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
EUR'000 Assets under Production Other Total
construction facilities
and wells
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
EUR'000 Goodwill Exploration Total
and evaluation
assets
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
Critical judgement - identification of impairment indicators
Under IAS 36 the Group is required to consider if there are any
indicators of impairment for property, plant and equipment. The
judgement as to whether there are any indicators of impairment
takes into consideration a number of internal and external factors,
including changes in estimated reserves, significant adverse
changes to production versus previous estimates of management,
changes in estimated future oil and gas prices, changes in
estimated future capital and operating expenditure to develop and
produce commercial reserves, and adverse changes in applicable tax
regimes. Where indicators are present and an impairment test is
required, the calculation of the recoverable amount requires
estimation of its value in use and/or fair value less costs of
disposal (FVLCOD) using discounted cash flow models or other
approaches. These assessments are performed on a cash-generating
unit (CGU) basis, unless a lower level is deemed appropriate.
The judgement as to whether there are any indicators of
impairment for intangible exploration assets is made by reference
to, among other factors, the indicators outlined in IFRS 6,
including the lack of planned or budgeted substantive expenditure
on a licence, a lack of commercially viable reserves discovered,
and other factors that indicate that the carrying amount of the
intangible asset is unlikely to be recovered in full from
successful development or by sale.
Key source of estimation uncertainty - estimated future cash
flows used in impairment testing
In performing impairment tests, management uses discounted cash
flow projections to estimate value in use or FVLCOD as an asset's
or CGU's recoverable amount. These forecasts include estimates of
future production rates of gas and oil products, commodity prices
and operating costs, and are thus subject to significant risk and
uncertainty. Changes to external factors and internal developments
and plans can significantly impact these projections, which could
lead to additional impairments or reversals in future periods.
Where applicable, a sensitivity analysis to the key estimates and
assumptions is outlined below.
Impairments of property, plant and equipment in the Netherlands
segment of EUR0.3 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 EUR44.3 million comprise:
- a full impairment of the carrying value attributed to the
Q11-B exploration asset (EUR26.8 million);
- a full impairment of the carrying value attributed to the
Q10-B exploration asset (EUR10.0 million); and
- a full impairment of the carrying value attributed to the
M10/M11 exploration asset (EUR7.5 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. EUR7.5 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 EUR86 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 & M11(1) 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, Kistos Energy
P1453(2) and P1678)(4) Limited Production Non-operated 20%
Benriach (licences
P2411 and P1453(2) Kistos Energy
) (4) Limited Exploration Non-operated 25%
Bunnehaven (licence Kistos Energy
P2415(3) ) (4) Limited Exploration Non-operated 25%
Cardhu (licence P2594) Kistos Energy
(4) Limited Exploration Non-operated 20%
Roseisle (licence Kistos Energy
P2604) (4) 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
Significant judgement - assessment of control
Judgement has been applied as to whether the Group has joint
control of the arrangement arising from the purchase of working
interests in the GLA. If joint control is not present, the
acquisition cannot be a business combination and would be accounted
for instead as an asset acquisition. Under the voting rights extant
in the joint operating agreements, no individual party has the
ability to veto (and thus have control over) day-to-day decisions
and activities of the joint arrangement. However, as unanimous
consent is required over activities that significantly affect the
returns of the arrangement, management has concluded the Group does
have joint control. As the acquired processes of the arrangement
are clearly substantive, and both outputs and inputs are present,
management has concluded that the transaction meets the definition
of a business and therefore the acquisition has been accounted for
using the acquisition method under IFRS 3.
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:
EUR'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 EUR0.4 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 (EUR39.3 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 EUR34.9 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 EUR15.8 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 EUR3.1 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 EUR0.1
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 EUR155.0 million. The acquisition consideration, management's
assessment of the net assets acquired, and subsequent goodwill
arising were as follows:
EUR'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 EUR15.0 million payable was
recognised on acquisition, and comprised the following:
-- EUR7.5 million payable by February 2022 upon confirmation by
Kistos of its intention to proceed with exploitation activities in
respect of Vlieland Oil (Orion); and
-- EUR7.5 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:
EUR'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 EUR125.9 million and
a loss after tax of EUR20.1 million in the period from acquisition.
If the acquisition had completed on 1 January 2022, consolidated
revenue for the Group would have been EUR568.4 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:
EUR'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 14 October
31 December 2020 to 31
2022 December 2021
Consolidated profit/(loss) for the period,
attributable to shareholders of the Group
(EUR'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 (EUR) 0.31 (0.68)
Diluted earnings/(loss) per share (EUR) 0.31 (0.68)
----------------------------------------------------- -------------- ----------------
3.2 General and administrative expenses
EUR'000 Year ended 31 December 14 October 2020
2022 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
EUR'000 Year ended 31 December 14 October 2020
2022 to 31 December
2021
Wages and salaries 6,286 2,585
Social security costs 910 272
Equity-settled share-based payments 538 -
(note 3.4 )
-------------------------------------- ------------------------ -----------------
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 14 October 2020
2022 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 EUR0.5
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 Grant date Number Vesting conditions Contractual
arrangement of shares life of options
Incentive awards 14 February 215,382 Employee remains in 10 years
2022 service during the
vesting period. Option
vest in equal instalments
on the first, second
and third anniversaries
of the awards
Matching awards 25 April 2022 125,690 Employee remains in 10 years
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
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 GBP GBP2.27 GBP2.64
Share price at grant date GBP3.57 GBP4.14
Exercise price GBP2.73 GBP3.43
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 EUR EUR2.71 EUR3.13
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
EUR'000 Year ended 31 December 14 October 2020
2022 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.
EUR'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
EUR'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 EUR48.0 million (2021: EUR40.3
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
EUR'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
EUR'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
EUR'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 EUR0.8 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.
EUR'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.
EUR'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 EUR0.2 million, and a 1% decrease would
have reduced the Group's profit after tax by approximately EUR0.2
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 EUR25/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: EUR0.6 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 EUR212.0 million as
at 31 December 2022 (2021: EUR77.3 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 EUR27.4 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:
EUR'000 Within 3 months 1-5 More than Total
3 months to 1 year years 5 years
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
EUR'000 EUR90 million EUR60 million Bond costs Total
bond bond
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 EUR87 million
bond with a new EUR90 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 EUR60 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
EUR'000 Currency Nominal Year Face value Carrying Face value Carrying
interest of maturity amount amount
rate
EUR90 million
bond EUR 8.75% 2024 21,572 22,706 90,000 88,042
EUR60 million
bond EUR 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 EUR21.6 million of bonds repurchased (but not
cancelled).
The fair value of the non-current borrowings is EUR85.4 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 EUR68.4 million in nominal
value of its EUR90 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 EUR6.4 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:
EUR'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
EUR90 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
EUR60 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
EUR'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 EUR180 thousand (2021: EUR90 thousand). The
total cash outflow for leases was EUR181 thousand (2021: EUR98
thousand). Expenses relating to low-value and short-term leases was
not material.
During 2022, additions of EUR1.3 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 Share Share Merger reserve Capital reorganisation
of shares capital premium (EUR'000) reserve (EUR'000)
(EUR'000) (EUR'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 GBP0.10 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 EUR50 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
EUR'000 31 December 31 December
2022 2021
Balance at beginning of the (5,890)
period -
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: EUR0.6 million). The hedge
reserve has been taxed at an effective rate of 50%.
Kistos NL2 held the following cash flow hedge during 2022:
Volume Price Period
(MWh) of hedge
Jan-Mar
Cash flow hedge 300,000 EUR25 MWh 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
EUR'000 Year ended 31 December 14 October 2020
2022 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:
EUR'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 21,799 -
deductible
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
EUR'000 31 December 31 December
2022 2021
Deferred tax liability 57,288
at beginning of period --
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 EUR36.8 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%.
Temporary differences
EUR'000 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 EUR1.0 million (2021: EUR1.9 million).
Tax losses of EUR5.4 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
Significant judgement - recognition of Solidarity Contribution
Tax provision
In October 2022, the EU member states adopted Council Regulation
(EU) 1854/2022, which required EU member states to introduce a
Solidarity Contribution Tax for companies active in the oil, gas,
coal and refinery sectors. The Dutch implementation of this
solidarity contribution has been legislated by a retrospective 33%
tax on 'surplus profits' realised during 2022, defined as taxable
profit exceeding 120% of the average taxable profit of the four
previous financial years. Companies in scope are those realising at
least 75% of their turnover through the production of oil and
natural gas, coal mining activities, refining of petroleum or coke
oven products.
The Group believes that there is an argument that Kistos NL2
B.V. is out of scope of the regulations as, in its opinion, less
than 75% of its turnover under Dutch GAAP (the relevant measure for
Dutch taxation purposes) was derived from the production of
petroleum or natural gas, coal mining, petroleum refining, or coke
oven products. Furthermore, the Group understands the
implementation of the tax, including its retrospective nature, is
subject to legal challenges by other parties. 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 EUR46.9 million relating to the Solidarity Contribution Tax in
the current tax charge for the year. This is the single most likely
amount of the charge if it becomes payable. The Group expects to
get further certainty around this tax position in 2024.
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.
EUR'000 Year ended 14 October
31 December 2020 to
2022 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 EUR938 thousand (2021:
EUR490 thousand).
7.1.2 Loans to key management personnel
EUR'000 Year ended 31 December 14 October 2020
2022 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 EUR56 thousand of rental and
other property-related costs (2021: EUR28 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 EUR75 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 EUR75 million relating to M10a and M11,
triggered at FID and payable upon first gas, based on US$3/boe of
sanctioned reserves; and
-- EUR10 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
EUR'000 EUR90 million EUR60 million Bond interest Amortised Other Lease
bond bond payable bond costs non-current liabilities
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:
EUR'000 Year ended 31 December Year ended 31 December
2022 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 V å r 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 Calculated as revenue from gas production divided by units
gas price 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 EUR0.5 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 and cash equivalents less face value of Nordic Bonds
cash 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 50(th) percentile estimate, equivalent to 2P
-------------------------------------------------------------------------
SGP Shetland Gas Plant
-------------------------------------------------------------------------
SodM State Supervisor of Mines
-------------------------------------------------------------------------
Solidarity A tax levied by the Dutch government, following the adoption
Contribution of Council Regulation (EU) 1854/2022, which required EU
Tax 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
Management believes that certain non-IFRS measures (also
referred to as 'alternative performance measures') are useful
metrics as they provide additional useful information on
performance and trends. These measures are primarily used by
management for internal performance analysis, are not defined in
IFRS or other GAAPs and therefore may not be comparable with
similarly described or defined measures reported by other
companies. They are not intended to be a substitute for, or
superior to, IFRS measures. Definitions and reconciliations to the
nearest equivalent IFRS measure are presented below.
B1 Pro forma information
Pro forma information shows the impact to certain results of the
Group as if the 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.
EUR'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).
EUR'000 Year ended Period ended
31 December 2022 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 (EUR/MWh) 5.8 3.7
Pro forma unit opex (EUR/MWh) 6.9 3.2
Appendix C Conversion Factors
37.3 scf in 1 Nm(3)
1.7 MWh in 1 boe
34.12 therms in 1 MWh
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
RNS may use your IP address to confirm compliance with the terms
and conditions, to analyse how you engage with the information
contained in this communication, and to share such analysis on an
anonymised basis with others as part of our commercial services.
For further information about how RNS and the London Stock Exchange
use the personal data you provide us, please see our Privacy
Policy.
END
FR FFFILEEIAFIV
(END) Dow Jones Newswires
May 30, 2023 02:00 ET (06:00 GMT)
Kistos (LSE:KIST)
Historical Stock Chart
From Apr 2024 to May 2024
Kistos (LSE:KIST)
Historical Stock Chart
From May 2023 to May 2024
