REG - Kistos Holdings PLC - Full-year results for the year ended 31/12/22
30/05/2023 07:15
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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 €517.2 million (2021: €102.9 million).
· Completed the acquisition of a 20% interest from TotalEnergies
E&P UK Limited ("TotalEnergies") in the GLA, more than doubling Kistos'
net daily production.
· Year-end 2P reserves of 12.7 MMboe increased to 36.3 MMboe on
completion of the Mime Petroleum A.S. ("Mime") transaction.
12 months ended 31 December 2022
2022 (actual) 2022 (pro forma)(1) 2021 (actual) 2021 (pro forma)(1)
Gas production(2) MM Nm(3) 391 556 145 268
Total production rate(3) Boe/d 10,600 10,900 4,300 5,000
Revenue €'000 411,512 568,445 89,628 116,731
Average realised gas price(2) €/MWh 98.7 93.8 57.4 39.8
Unit opex(4) €/MWh 5.8 6.9 3.7 3.2
Adjusted EBITDA(4) €'000 380,015 517,202 78,861 102,862
Statutory profit/(loss) before tax €'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 €'000 211,980 211,980 77,288 77,288
1. Pro forma figures include the GLA as if it had been
acquired on 1 January 2022. The acquisition completed on 10 July 2022. Pro
forma figures for 2021 include the results of Kistos NL1 and Kistos NL2 as if
they had been acquired on 1 January 2021.
2. Comparative information has been restated to align with
current year allocation methodology.
3. Total production rate includes gas, oil and natural gas
liquids and is rounded to the nearest 100 barrels of oil equivalent per day.
Actual production rates include impact from acquired businesses only from date
of acquisition completion.
4. Non-GAAP measure. Refer to Appendix B to the financial
statements for definition and calculation.
5. Certain pro forma equivalents are not applicable or
meaningful. The GLA acquisition comprised the purchase of interests in an
unincorporated joint arrangement with no pre-existing IFRS income statement,
balance sheet or cash flow statement from which to derive pro forma
information.
Financial
Strong cash generation in both halves of the year, with movements in gas
prices and production rates offsetting each other
· Profit after tax of €73 million, including €44 million of
impairment charges relating to exploration assets in the Netherlands, €27
million of gains from changes and releases in acquisition contingent
consideration balances, and a total tax charge of €228 million.
· The tax charge (resulting in an effective tax rate for 2022 of 89.8%)
includes impact of the Energy Profits Levy in the UK and the EU Solidarity
Contribution Tax in the Netherlands.
· Cash balances on 31 December 2022 of €212 million (31 December
2021: €77 million) and net cash of €130 million (31 December 2021: net
debt of €73 million).
· Retired 46% of outstanding debt by repurchasing €68 million of
Nordic Bonds, leaving €82 million outstanding.
· Capital expenditure on a cash basis, excluding business acquisitions,
was €19.5 million.
Operational
Increasing the Group's production base with organic and inorganic growth
· Year-end 2P reserves of 12.7 MMboe increased to 36.3 MMboe on
completion of the Mime Petroleum A.S. (Mime) transaction.
· Drilling of the Benriach exploration well (Kistos 25%) approved and
was spudded in March 2023.
· Estimated Scope 1 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 Advisor) Tel: 0203 745 4960
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 €250 million of Adjusted EBITDA in 2022. The headline cost of
acquiring these assets was US$125 million, based on an effective economic date
of 1 January 2022. The final firm cash consideration payment was US$43
million, the difference being the post-tax cashflows generated from the assets
between the effective economic date and the completion date of 10 July 2022.
Having completed three acquisitions to date, we remain focused on building the
business and we continue to evaluate a pipeline of business development
opportunities, which includes geographies other than the Netherlands and the
UK. Nevertheless, if we are to add value for shareholders, it is critical that
we maintain our financial discipline and avoid overpaying for assets. Hence,
the Board will consider making cash distributions to shareholders if
attractive opportunities cannot be identified. It is in this context we
decided not to pursue a proposed combination with Serica Energy last summer.
While both the Kistos and Serica Boards agreed on the strong industrial logic
of a combination, terms could not be agreed that the Board believed fully
reflected the value of Kistos.
Importantly, while we assess other potential acquisitions, we are pursuing the
organic growth opportunities within our existing portfolio. During 2022, the
Orion oil field development project completed the Concept Assess phase and
moved into the Concept Select phase and we expect to submit a Field
Development Plan (FDP) and permitting requests to the authorities before the
end of this year. In addition, we remain mindful of the opportunity to develop
the Q11-B gas discovery but at present work is on hold due to the uncertainty
surrounding the tax regimes in the Netherlands. This has caused us to fully
impair the value of the assets until such time as there is sufficient fiscal
clarity or incentives available to encourage investment in energy security.
In the UK, the Board of Directors has approved Kistos' participation in the
Benriach exploration well, (Kistos 25%) west of Shetland. The well was spudded
in March 2023, targeting 638 Bcf (operator's gross P50 resource estimate) with
results expected in mid-2023. The Board is also ready to sanction the Edradour
West and Glendronach developments in the GLA, west of Shetland, with a
decision by the joint-venture partners as to the order and timing of
developments expected to be taken later in 2023 to allow further technical
reviews to be undertaken with the aim of reducing costs.
Central to our operations is our health, safety and environmental (HSE)
performance. While our overall performance was positive, we did suffer one
lost time incident in early 2022 on the Borr drilling rig, but we did not
suffer any medical treatment cases and there was no increase in first aid
cases. This was despite having drilling rigs on location for more than six
months of the year.
Following an upgrade of the wind turbines in 2021, the renewably powered Q10-A
platform maintained its excellent emissions intensity track record during 2022
with Scope 1 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 €46.9 million relating to the Solidarity
Contribution Tax in the current tax charge for the year.
Alongside several of our counterparties in the sector, we are lobbying the UK
and Dutch Governments to address our concerns and take action that will save
jobs, reduce carbon emissions, reduce the balance of payments deficit and
minimise dependence on energy imports. We hope they will listen and act
accordingly, but we cannot be certain of that. Therefore, as stated earlier,
our focus has to be elsewhere, and our pipeline of business development
opportunities now includes assets in jurisdictions other than the UK and the
Netherlands.
To that effect, in April 2023 we announced that we had reached a conditional
agreement to acquire Mime Petroleum A.S. (Mime). The transaction completed in
May, and marks our entry into the Norwegian Continental Shelf (NCS), adding 24
MMboe of 2P reserves plus 30 MMboe of 2C resources, primarily oil. In terms of
production, Mime will add over 2,000 boe/d immediately and help to boost Group
output to in excess of 15,000 boe/d in 2025 once the Jotun FPSO (on the Balder
X development) is onstream. The transaction will also act as a platform for
growth for Kistos and Mime in Norway.
Adjusted EBITDA for 2022 was €380.0 million (2021: €78.9 million) while
adjusted pro forma EBITDA, which includes a full 12-month contribution from
the GLA, was €517.2 million (2021: €102.9 million). This was split evenly
between the first half and the second half of the year, with movements in gas
prices and production rates offsetting each other. Hence, we ended the year
with net cash of €130.4 million (2021: net debt of €72.7 million), which
was achieved after paying for the GLA acquisition and cash capital expenditure
of €19.5 million (2021: €20.0 million).
Finally, I would like to thank our employees and contractors for their work
and commitment to the Company and to thank our suppliers, co-venturers and
others for their continued support. From a standing start in the fourth
quarter of 2020, we have built an excellent platform and we will seek to
deploy further capital in the right opportunities or make distributions to
shareholders. Although we do not set explicit long-term targets for reserves
or production, our focus for which we are well-placed is to continue
generating substantial returns for investors and look forward to reporting
further progress during 2023.
Operating Review
2022 was an important year for Kistos, as our acquisition of a 20% interest in
the GLA consolidated our position as an operating business with significant
reserves, production and technical expertise.
Our Dutch assets contributed a full 12 months of production to the Group for
the first time and the pro forma Group average gas production rate was 1.52
million 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.€18 million pre-tax or c.€3
million post tax.
Other
UK 33(rd) Round (Kistos 25%)
Kistos is part of a TotalEnergies-led joint venture that has re-applied for
six blocks or part-blocks in the GLA as part of the UK Government's 33rd
Offshore Oil and Gas Licensing Round. The acreage covers 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 €7.5 million has been impaired in full, although this was offset
by a release of contingent consideration payable of the same amount.
Outside of the M10/M11 area, in January 2023 Kistos was awarded the P12b, Q13b
and Q14 licences covering a total acreage of 507 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 2022 31 December 2022 (pro forma)(1) 31 December 2021 31 December 2021
(actual)
(actual) (pro forma)(1)
Revenue €'000 411,512 568,445 89,628 116,731
Average realised gas price €/MWh 98.7 93.8 57.4 39.8
Unit opex(2) €/MWh 5.8 6.9 3.7 3.2
Adjusted EBITDA(2) €'000 380,015 517,202 78,861 102,862
Profit before tax €'000 254,125 n/a(3) (73,857) (65,940)
Earnings/(loss) per share € 0.31 n/a(3) (0.68) n/a(3)
Operating cashflow €'000 290,473 n/a(3) 47,956 n/a(3)
Cash capital expenditure €'000 19,454 n/a(3) 19,958 n/a(3)
Closing cash €'000 211,980 211,980 77,288 77,288
1. Pro forma figures include the GLA as if it had been acquired on 1 January
2022. The acquisition completed on 10 July 2022. Pro forma figures for 2021
Include the results of Kistos NL1 and Kistos NL2 as If they had been acquired
on 1 January 2021.
2. Non-IFRS measure. Refer to Appendix B to the financial statements for
definition and calculation.
3. Certain pro forma equivalents not applicable. The GLA acquisition comprised
the purchase of Interests In an unincorporated joint arrangement with no
pre-existing IFRS Income statement, balance sheet or cash flow statement from
which to derive pro forma Information
Production and revenue
Gas production on a working interest basis totalled 391 million 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 €98.7/MWh
versus €57.4/MWh in 2021 and this, combined with higher production, resulted
in total revenue from gas sales increasing by 459% year-on-year to €411.5
million. This includes the impact of the hedging programme in the Netherlands
which ended in March 2022, whereby 300,000 MWh was hedged at €25/MWh. On a
pro forma basis, these figures were €93.8/MWh and €568.4 million. Revenue
from natural gas liquids (NGL) and crude oil sales was €nil but €10.7
million on a pro forma basis, reflecting the timing of liftings in the
periods. This compared with €0.1 million and €0.6 million on a pro forma
basis in 2021.
Costs
GLA inevitably costs more to operate than Q10-A, with the fields lying in much
deeper water, further from shore and a much greater distance to the market.
Hence, unit opex costs for the period on a consolidated level increased from
€3.7 per MWh in 2021 to €5.8 per MWh in 2022. On a pro forma basis, there
was a more pronounced increase from €3.2 per MWh in 2021 to €6.9 per MWh
in 2022 reflecting a full year of higher GLA operating costs.
During 2022, Kistos incurred pre‑FID development expenses of €1.8 million
(2021, €4.5 million) on potential alternative evacuation routes for the
Q10-A platform in addition to progressing development on Orion. As FID was not
taken on the alternative evacuation routes, and Orion is still subject to FID,
these costs have been expensed in the profit and loss account. Following the
decision to continue exporting Q10-A gas via the P15-D platform, no further
expenditure is anticipated in 2023.
Adjusted EBITDA
€'000 Year ended 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 movements 26,993 -
Operating profit/(loss) 276,256 (62,772)
1. Pro forma figures include results
from GLA as if it had been acquired on 1 January 2022, and, for 2021, as if
the Tulip Oil acquisition had completed on 1 January 2021. The acquisitions
completed on 10 July 2022 and 20 May 2021 respectively.
Adjusted EBITDA was €380.0 million or €81.9 per MWh equivalent of
production in 2022. Both figures were substantially ahead of the comparable
figures for the period to 31 December 2021 of €78.9 million and €47.5 per
MWh equivalent respectively, primarily driven by the material increase in
commodity prices during the period. On a pro forma basis, Adjusted EBITDA was
€517.2 million or €76.7 per MWh equivalent of production versus €102.9
million or €33.4 per MWh equivalent in 2021.
The impairments primarily relate to the Q11-B and Q10-B assets (€36.8
million), which have been impacted by changes to the fiscal regime introduced
by the Dutch tax authorities during 2022. These have introduced uncertainty
into what was previously a stable and predictable fiscal regime and, unlike
equivalent measures in the UK, do not incentivise licence holders to invest
further by means of enhanced deductions for investment capital expenditure.
Pending further clarity on these measures and whether they are to be extended,
there is currently no substantive expenditure on these licences budgeted or
planned. As such, there is no longer sufficient certainty over whether the
carrying value can be recovered from future development the amounts relating
to Q11-B have been fully impaired.
Additionally, a charge of €7.5 million was recognised against the M10/M11
licences. This has been impaired because, as at the balance sheet date, the
Group's application to renew the relevant licence had not been approved and
there is uncertainty as to whether the Group would be successful in its appeal
and/or re-application. As the Group no longer holds the licences, the
contingent consideration payable to seller, which would have crystallised upon
taking forward further development, has been derecognised resulting in an
offsetting €7.5 million gain.
Capital expenditure
Consistent with our growth plans and to ensure we maximise the value of our
asset portfolio, capital expenditure in 2022 was €19.5 million (2021 €20.0
million) on a cash basis. The majority of this related to our two drilling
campaigns. With FID for Glendronach delayed, and Orion still in the Concept
Select phase, capital expenditure in 2023 will not ramp up as much as we
originally expected. Out of currently anticipated cash spend of €40-45
million, approximately three-quarters relates to the Dutch drilling campaign
that completed in March 2023 or to the pre-tax costs of the Benriach
exploration well. On a post-tax basis, we expect the Benriach costs to be
c.15% of the pre-tax costs, as a result of the interaction between capital
expenditure and the EPL. Kistos expects Mime's capital expenditure for the
full year 2023 to be up to $130 million. Tax relief is available on this
expenditure at a rate of 78% and is expected to result in a cash tax refund in
December 2024.
Profit/loss before tax
Operating profit for the period was €276.3 million (2021: operating loss of
€62.8 million) and a profit before tax of €254.1 million (2021: loss
before tax of €73.9 million). This figure was after impairments of €44.5
million (2021: €121.0 million), and net finance costs of €22.1 million
(2021: €11.1 million), including interest charges of €10.5 million
associated with Kistos NL2's Nordic Bonds and a non-cash loss on redemption
of €6.4 million relating to repurchases of €68.4 million of Nordic Bonds
during the period (arising as the bonds were repurchased at a small premium to
par).
Balance sheet
At the end of 2022, the Group held cash and cash equivalents of €212.0
million (31 December 2021, €77.3 million) and net cash of €130.4 million
(31 December 2021, net debt of €72.7 million). The increase in net cash of
over €200 million was achieved after capital expenditure and acquisition
cash outflows of €67.0 million and bond repurchases of €71.8 million, and
reflected a 605% increase year-on-year in operating cash flow from €48.0
million to €290.5 million.
Taxation
The effective tax rate for the Group in 2022 was 89.8% (2021: 45.7%). The
increase was driven by the introduction, and subsequent increase and
extension, of the Energy Profits Levy in the UK and the imposition of the
Solidarity Contribution Tax in the Netherlands. The latter is a one-off tax
levied on so-called 'surplus profits' generated in 2022. The Group paid
€65.7 million in cash taxes in 2022 (2021, €0.9 million), all relating to
Dutch tax liabilities. Due to the timing of the GLA acquisition, no cash
corporation tax was due or paid during 2022 in the UK.
As a result of the above, higher gas prices during the year, and adverse
changes to the fiscal regime in the UK and the Netherlands, our current tax
liability has increased from €15.0 million at the end of 2021 to €143.1
million at the end of 2022. This includes €46.9 million in respect of the
Solidarity Contribution Tax. The payment of these liabilities and the
normalisation of the timing of our tax payments will impact operating cash
flow in 2023 and 2024.
The Group understands the introduction and implementation of the Solidarity
Contribution Tax is subject to legal challenges by other parties. Furthermore,
due to differences between DAS 270 of Dutch GAAP (the relevant revenue
recognition standard for determining if the tax is due) and IFRS 15, the Group
believes it has strong arguments that its Dutch subsidiary is out of scope of
this tax (see note 6.3 to the financial statements). Therefore, it is not
certain at this stage if the Group will be required to settle this tax
liability, notwithstanding the inclusion of the tax charge as a liability in
these financial statements.
Cash flow
€'000 Year ended 31 December 2022 Period ended 31 December 2021
Cash and cash equivalents at beginning of period 77,288
-
Net cash generated from operating activities 290,473 47,956
Net cash used in investing activities (66,772) (120,654)
Net cash from financing activities (83,816) 149,986
Net increase in cash and cash equivalents 139,885 77,288
Foreign exchange losses (5,193) -
Cash and cash equivalents on 31 December 2022 211,980 77,288
ESG Outlook and Non-Financial Performance
Environment
Acting on climate change
We believe that natural gas has an important role to play in the energy
transition, bridging the gap on the journey from fossil fuels to a renewable,
zero-carbon future. To that end, we continue to explore ways to produce gas
with a very low carbon footprint in an environmentally benign way as we seek
to support the UK's and the Netherlands' net zero ambitions. In 2022 plans
were made to invest to increase the wind generation capacity on our Q10-A
offshore gas production platform by installation of a third wind turbine. This
will be implemented during 2023.
Direct emissions and air quality
Our Scope 1 emissions levels are minimal, thanks to the solar panels and wind
turbines that power the Q10-A platform. In 2022, we estimate the Scope 1
emissions related to our activities offshore the Netherlands were 0.002 kg
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 Element NL, OEUK, BRINDEX and other industry Risk has increased
There are risks that changes in national government policies towards oil and
CEO associations, the Group engages with the respective governments and other
gas-focused companies adversely impact the ability of the Group to deliver its appropriate organisations to ensure the Group is kept abreast of expected
strategy. This could result in challenges, delays and refusals related to potential changes and takes an active role in making appropriate
permitting applications for development, appraisal and exploratory drilling in representations.
Kistos-owned or targeted blocks.
Growth of reserves base Andrew Austin The Group identifies and evaluates a broad range of acquisitions and similar No change in risk
The Group's growth strategy is dependent on identifying new reserves and Executive Chairman opportunities and maintains strong relationships within the industry.
resources, and does so through development and acquisition. Organic growth is Potential opportunities are evaluated internally and with support from subject
focused on developing existing resources into producible reserves. matter experts where appropriate. A rigorous assessment process evaluates and
determines the risks associated with all potential business acquisitions and
As part of this growth strategy, there is a risk that the Group may fail to strategic alliances, including conducting stress-test scenarios for
identify attractive acquisition opportunities or select inappropriate sensitivity analysis. If applicable, each assessment includes an analysis of
exploration work programmes. the Group's ability to operate in a new jurisdiction.
Exploration drilling may deliver adverse results due to factors including poor Exploration, appraisal and development cases are robustly assessed and stress
quality (or misinterpretation of) data, failure/underperformance of offshore tested against cost, price and taxation sensitivities.
vessels or other crucial equipment, unforeseen problems occurring during
drilling and delays to offshore operations due to unfavourable weather.
The long-term commodity price forecast and other assumptions used when
assessing potential projects and investment opportunities can have a
significant influence on the forecast return on investment.
Inappropriately valued targets may result in overpaying for acquisitions,
leading to subsequent impairments of assets and goodwill and lead to adverse
reputational and share price impact. Similarly, an inability to convert
existing resources to reserves, or dry holes experienced during drilling
campaigns, may give rise to impairments and reduce future forecast cash flows.
Climate change Peter Mann The Board actively reviews the Group's strategy towards energy transition with No change in risk
Changes in laws, regulations, policies, obligations and social attitudes
CEO an aim to provide long‑term returns to shareholders, and regularly considers
relating to the transition to a lower carbon economy could lead to higher the impact of climate change and potential changes to policy in its decision
costs, or reduced demand and prices for gas, impacting the profitability of making. It continues to investigate and implement actions on its existing
the Group. Sources of debt and equity finance may become more expensive or assets that could reduce its environmental footprint, and environmental
restricted as investors diversify away from oil and gas-based investments. considerations are a key factor in determining any potential inorganic growth
activity.
The value of projects is discounted in the future for later life production to
take into account possible reduced demand for hydrocarbons.
The Group stress tests its budgets and forecasts in respect to the cost of
carbon emission allowances.
Cyber security Richard Slape The Group outsources its provision of IT equipment and help-desk services to No change in risk
Breaches in, or failures of, the Group's information security management could
CFO third parties. Various network management systems are used to protect the
adversely impact its business activities. The Group's information security Group's IT environment.
management model is designed with defensive structural controls to prevent and
mitigate the effects of computer risks. It employs a set of rules and
procedures, including a Disaster Recovery Plan, to restore critical IT
functions.
Joint venture Peter Mann The Group has representatives on all of the joint ventures' committees New risk
As a minority non-operating partner in the GLA partnership, the interests and objectives of the partners may not be aligned. This may result in longer decision making processes, programmes approved which are not in line with the Group's strategy and/or investment cases which the Group believes are in its best interests not voted through by partners.
(including operating, finance and technical) and regularly engages with the
CEO joint-venture operator and other participants in the joint venture with
regards to key decision and strategic direction.
Operational
HSE and compliance Peter Mann The Group works closely with regulators to ensure that all required planning Increase in risk
The Group is exposed to various risks in relation to HSE, compliance, CEO consents and permits for operations are in place and maintains continual
planning, environmental, regulatory, licensing and other permitting rules dialogue with all stakeholders to understand emerging requirements.
associated primarily with production operations, drilling and construction.
All activities are conducted in accordance with Board-approved policies,
A loss of hydrocarbon containment, in addition to causing harm to the standards and procedures. The Group requires adherence to its Code of Conduct
environment, could result in reputational damage and incur financial and runs compliance programmes to provide assurance on conformity with
penalties. 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 and operational performance Peter Mann The Group continuously reviews production performance from each of its wells Decrease in risk
The Group's production volumes (and therefore revenue) are dependent on the CEO to enable it to predict well performance and plan well-intervention activities
operational performance of its producing assets. The Group's producing assets as needed.
are subject to operational risks, including no critical spare equipment or
plant availability during the required plant maintenance or shutdowns; asset To the extent possible discussions are held with third parties to manage
integrity and health, safety, security and environment incidents; and low shutdowns both planned and unplanned.
reserves recovery from the field and exposure to natural hazards such as
extreme weather events. Planned and unplanned downtime assumptions are built into the corporate
budgeting cycle and cash flow projections.
Following acquisition of interests in the producing GLA assets, the Group's
production base is diversified and thus is no longer exposed to a single
source of revenue.
Project delivery Peter Mann Each project has a clear project delivery framework with a responsible project Increase in risk
Risk of delays in project delivery and higher costs being incurred, especially
CEO lead. Delivery against the project objectives, timeline and cost are regularly
under the current high inflationary environment. monitored. Risks being faced are discussed and where appropriate risk
mitigation steps implemented. Project costs are stress tested against cost
increases with adequate contingency built in to estimates.
Retention of key personnel Peter Mann The Board seeks to cultivate a safe, respectful working environment where No change in risk
The Group may not be able to retain key personnel, and there can be no
CEO people can thrive. Management has undertaken a benchmarking exercise on
assurance that the Group will be able to continue to attract and retain all salaries to ensure that acquired staff are retained through a strong
personnel suitably qualified and competent necessary for the safe and remuneration culture. Workplace surveys are undertaken to ascertain morale and
efficient operation and development of its business. employee concerns and allow management to swiftly address any issues. A
long-term share incentive plan is now in place for key staff in the UK and the
Netherlands.
Financial
Commodity price risk Richard Slape The Board continuously reviews the oil and gas markets to determine whether No change in risk
The Group's cashflow and results are heavily dependent on natural gas and CFO future hedges are needed and has the necessary contracts in place to undertake
other commodity prices, which are dependent on several factors including the hedging activities if required.
impact of climate change concerns, geopolitics (including events such as the
Russia-Ukraine conflict) and regulatory developments. Cash flow projections and liquidity analyses are regularly tested for downside
price scenarios.
Liquidity risk Richard Slape Management regularly reviews the Group's cash forecasts and its covenants to No change in risk
Adverse changes to production, commodity prices, taxation and surety bond CFO ensure an adequate headroom of cash availability. The Group is in regular
requirements may put pressure on the Group's available liquidity, constraining dialogue with potential providers of finance and surety bond providers.
its options to grow the business or, in the worst cases, cause it to breach
its bond covenants or become insolvent.
Decommissioning costs and timing Richard Slape The Group mitigates this risk through in-house decommissioning experience, No change in risk
The future costs and timing of decommissioning is a significant estimate; any CFO coupled with a continued focus on delivering asset value to defer abandonment
adverse movement in price, operational issues and changes in reserves and liabilities.
resource estimates could have a significant impact on the cost and timing of
decommissioning. Where decommissioning costs are to be shared as part of a Decommissioning security arrangements and postings in place for UK assets
joint venture, risk of partners not fulfilling their commitments leaving which mitigate risk from a regulatory and joint-venture partner perspective.
remaining partners exposed. Changes to commodity prices, the taxation regime,
inflation rates and other factors may mean that the Group is not be able to The Group maintains strong relationships with surety bond providers and have
renew its surety bonds in respect of its DSA obligations, resulting in the obtained comfort that the surety market can continue to provide security for
Group having to cover its obligations fully in cash, restricting the amount of the expected DSA provisions.
funds available for other opportunities and day-to-day operations.
Taxation Richard Slape The Group engages with various industry bodies to raise concerns and suggest New risk
Longer-term additional and increased taxes imposed on oil and gas companies by
alternative approaches to proposed taxation policies. Projects and liquidity
governments in reaction to so-called 'windfall profits' arising from CFO projections are modelled with various tax sensitivities in place.
short-term movements in commodity prices have led to a higher tax burden.
Uncertainty over tax regimes may also hinder future investment decisions and The Group engages the support and advice of external experts and legal counsel
reduce the returns from, and profitability of, operations. on taxation matters for areas where there exists significant uncertainty and
judgement.
Should the Dutch tax office rule unfavourably against the Group with regards
to the Solidarity Contribution Tax, this would have a material impact to the The Group will review its investment strategy and may decide not to invest
Group's projected cash position. further in, or consider withdrawing from, jurisdictions with a recent history
of significant tax changes, implementation of retrospective taxation, or where
the taxation regime proves too burdensome.
Consolidated Financial Statements
Consolidated income statement
€'000 Note Year ended 31 December 2022 14 October 2020 to 31 December 2021
Revenue 2.1 411,512 89,628
Other operating income 11 61
Exploration expenses (374) (123)
Production costs 2.3 (22,927) (6,143)
Development expenses 2.4 (1,752) (4,456)
General and administrative expenses 3.2 (9,426) (7,426)
Depreciation and amortisation 2.6 (83,234) (13,277)
Impairments 2.8 (44,547) (121,036)
Change in fair value and releases of contingent consideration 2.10.2 26,993 -
Operating profit/(loss) 276,256 (62,772)
Interest income 3.5 267 -
Interest expenses 3.5 (11,283) (8,993)
Other net finance costs 3.5 (11,115) (2,092)
Net finance costs (22,131) (11,085)
Profit/(loss) before tax 254,125 (73,857)
Tax (charge)/credit 6.1 (181,229) 33,749
Solidarity Contribution Tax charge 6.3 (46,935) -
Total tax (charge)/credit 6.1 (228,164) 33,749
Profit/(loss) for the period 25,961 (40,108)
Basic earnings/(loss) per share (€) 3.1 0.31 (0.68)
Diluted earnings/(loss) per share (€) 3.1 0.31 (0.68)
Consolidated statement of other comprehensive income
€'000 Note Year ended 31 December 2022 14 October 2020 to 31 December 2021
Profit/(loss) for the period 25,961 (40,108)
Items that may be reclassified to profit or loss:
Losses on cash flow hedges 5.4 (9,404) (38,624)
Hedging losses reclassified to profit or loss 5.4 21,185 26,843
Income tax on items of other comprehensive income 5.4 (5,891) 5,891
Foreign currency translation differences (43) 382
Total other comprehensive income, net of tax 31,808 (45,616)
Consolidated balance sheet
€'000 Note 31 December 2022 31 December 2021
Non-current assets
Goodwill 2.7 10,913 -
Exploration and evaluation assets 2.7 43,338 45,771
Property, plant and equipment 2.6 282,474 171,227
Deferred tax assets 6.2 566 13,496
Investment in associates 61 -
Other long-term receivables 102 -
337,454 230,494
Current assets
Inventories 4.5 9,688 902
Accrued income 4.2.1 47,962 40,299
Other receivables 4.2 6,600 8,439
Cash and cash equivalents 4.1 211,980 77,288
276,230 126,928
TOTAL ASSETS 613,684 357,422
Equity
Share capital 5.3 9,464 9,627
Share premium 5.3 - 94,181
Merger reserve 5.3 140,105 14,734
Capital reorganisation reserve 5.3 (80,995) -
Hedge reserve 5.4 - (5,890)
Translation reserve 5.5 339 382
Share-based payment reserve 5.6 538 -
Retained earnings 33,261 (42,463)
Total equity 102,712 70,571
Non-current liabilities
Abandonment provision 2.5 123,503 15,904
Bond debt 5.1 80,800 145,074
Deferred tax liabilities 6.2 118,325 57,288
Other non-current liabilities 4.4 4,197 31
326,825 218,297
Current liabilities
Trade payables and accruals 4.3 19,372 23,479
Current tax payable 143,134 14,980
Abandonment provision 2.5 2,585 1,272
Other liabilities 4.4 19,056 28,823
184,147 68,554
Total liabilities 510,972 286,851
TOTAL EQUITY AND LIABILITIES 613,684 357,422
The notes on pages xx to xx are an integral part of these financial
statements and were approved by the Board of Directors on xx 2023.
Andrew Austin Executive Chairman
Consolidated statement of changes in equity
€'000 Note Share Share Merger reserve Capital reorganisation reserve Hedge Translation reserve Retained earnings Share-based payment reserve Total
premium
reserve
equity
capital
At 14 October 2020 - - - - - - - - -
Loss for the period - - - - - - (40,108) - (40,108)
Other comprehensive income - - - - (5,890) 382 - - (5,508)
Total comprehensive income for the period - - - - (5,890) 382 (40,108) - (45,616)
Transactions with owners
Shares issued in the period 5.3 9,627 94,181 14,734 - - - - - 118,542
Share issue costs 5.3 - - - - - - (2,355) - (2,355)
Total transactions with owners 9,627 94,181 14,734 - - - (2,355) - 116,187
At 31 December 2021 9,627 94,181 14,734 - (5,890) 382 (42,463) - 70,571
Profit for the year - - - - - - 25,961 - 25,961
Other comprehensive income - - - - 5,890 (43) - - 5,847
Total comprehensive income for the year - - - - 5,890 (43) 25,961 - 31,808
Transactions with owners
Capital reduction 5.3 - (35,266) (14,734) - - - 50,000 - -
Equity-settled share-based payments 3.4 - - - - - - - 538 538
Capital re-organisation 5.3 (163) (58,915) 140,105 (80,995) - - (237) - (205)
Total transactions with owners (163) (94,181) 125,371 (80,995) - - 49,763 538 333
At 31 December 2022 9,464 - 140,105 (80,995) - 339 33,261 538 102,712
Consolidated cash flow statement
€'000 Note Year ended 31 December 2022 14 October 2020 to 31 December 2021
Cash flows from operating activities:
Profit/(loss) for the period 25,961 (40,108)
Tax charge/(credit) 6.1 228,164 (33,749)
Net finance costs 3.5 22,131 11,085
Depreciation and amortisation 2.6 83,234 13,277
Impairment charge 2.8 44,547 121,036
Change in contingent consideration payable 2.10.2 (26,993) -
Share-based payment expense 3.4 538 -
Taxes paid (65,729) (890)
Abandonment costs paid 2.5 (2,319) -
Increase in trade and other receivables (1,382) (40,990)
(Decrease)/increase in trade, other payables and provisions (13,094) 18,582
Increase in inventories (4,717) (287)
Decrease in other non-current assets/liabilities 132 -
Net cash inflow from operating activities 290,473 47,956
Cash flows from investing activities:
Payments to acquire fixed assets (19,454) (19,958)
Acquisition of business 2.10 (40,047) (100,696)
Payment of contingent consideration 2.10.2 (7,500) -
Interest received 229 -
Net cash outflow from investing activities (66,772) (120,654)
Cash flows from financing activities:
Proceeds from share issue 5.3 - 102,441
Costs incurred for share issue 5.3 - (2,355)
Repayment of long-term payables (209) (79)
Bond interest paid (11,566) (7,461)
Other interest paid 3.5 (268) -
Proceeds from bond refinancing 5.1 - 3,000
Bond issue costs 5.1 - (2,933)
Bond redemption costs and repurchase of own bonds 5.1.1 (71,773) (2,627)
Proceeds from bond issue 5.1 - 60,000
Net cash (outflow)/inflow from financing activities (83,816) 149,986
Increase in cash and cash equivalents 139,885 77,288
Cash and cash equivalents at start of period 4.1 77,288 -
Effects of foreign exchange rate changes (5,193) -
Cash and cash equivalents at end of period 4.1 211,980 77,288
Notes to the Consolidated Financial Statements
Section 1 General information and basis of preparation
Kistos Holdings plc (the Company) is a public company, limited by shares,
incorporated and domiciled in the United Kingdom and registered in England and
Wales under the Companies Act 2006 (registered company number 14490676). The
nature of the Company and its consolidated subsidiaries' (together, the
'Group') operations and principal activity is the exploration, development and
production of gas and other hydrocarbon reserves principally in the North Sea
and creating value for its shareholders through the acquisition and management
of companies or businesses in the energy sector.
1.1 Basis of preparation and consolidation
The financial statements have been prepared under the historical cost
convention (except for derivative financial instruments and contingent
consideration assumed in a business combination, which have been measured at
fair value,) in accordance with UK-adopted International Accounting Standards,
in conformity with the requirements of the Companies Act 2006 and in
accordance with the requirements of the Alternative Investment Market (AIM)
Rules.
These financial statements represent results from continuing operations, there
being no discontinued operations in the periods presented.
Kistos Holdings plc, a company registered in England and Wales under the
Companies Act 2006 with registered company number 14490676, was incorporated
on 17 November 2022 in England and Wales and its shares, with effect from 22
December 2022, are publicly traded on AIM in London. On 22 December 2022, by
means of a Scheme of Arrangement, the Company became the new parent company
for the Kistos Group of companies; the previous parent company being Kistos
plc (a company registered in England and Wales under the Companies Act 2006
with registered company number 12949154). Following the Scheme of Arrangement,
shareholders in Kistos plc received the same number and nominal value of
Kistos Holdings plc ordinary shares. As the owners of the original parent had
the same absolute and relative interests in the net assets of the original
group and the new group immediately before and after the reorganisation, these
consolidated financial statements of Kistos Holdings plc are presented as if
the Company headed the new group for all of the current and prior reporting
period. The change in parent company and legal capital of the group has been
reflected in the statement of changes in equity.
These consolidated financial statements cover the calendar year 2022, which
ended at the balance sheet date of 31 December 2022. The comparative period is
the long period of account from 14 October 2020 to 31 December 2021.
1.2 Going concern
These financial statements have been prepared in accordance with the going
concern basis of accounting. The forecasts and projections made in adopting
the going concern basis take into account forecasts of commodity prices,
production rates, operating and general and administrative (G&A)
expenditure, committed and sanctioned capital expenditure, and the timing and
quantum of future tax payments.
The Group's cash balances as at the end of April 2023 (the latest practicable
date of preparing these financial statements) was €268 million. To assess
the Group's ability to continue as a going concern, management evaluated cash
flow forecasts for the period to December 2024 (the going concern period), by
preparing a base case forecast and various downside sensitivities.
The base case going concern assessment assumed the following:
· Q10-A production in line with latest internal forecasts, taking
into account the results of the recently completed well intervention campaign
which finished in March 2023;
· GLA production in line with latest available operator forecasts;
· Commodity prices based on observable forward curves prevailing at
the latest practicable date;
· Committed and contracted capital expenditure only (being
primarily the costs of the Benriach well campaign currently underway and
Mime's share of Balder X capital expenditure);
· Obligations under Decommissioning Security Agreements (DSAs) for
the GLA fields satisfied by the purchase of surety bonds in Q4 2023 (in
respect of obligations for 2024) based on the most recent funding requirement
and DSA model received from the operator, and at a similar cost to 2023;
· Completion of the acquisition of Mime Petroleum (note 7.5.3) in
July 2023 (for which there is only $1 upfront cash consideration, and any
contingent consideration expected to be payable January 2025 at the earliest),
with the Group assuming Mime's restructured debt from that point and
consolidating Mime's expected future cashflows (including revenues from oil
production, capital expenditure and corporation tax rebates); and
· Settlement of the €47 million Solidarity Contribution Tax
charge in Q2 2024 (notwithstanding that the Group believes it is out of scope
of the charge).
This base case forecast demonstrated that the bond covenants (minimum
liquidity and leverage ratio) were complied with and that the Group had
sufficient cash to meet its obligations throughout the going concern period.
A key assumption within the forecast is the continued availability of surety
bonds used to cover obligations under Decommissioning Security Agreements
(DSAs). At 31 December 2022, the Group had €27.4 million of surety bonds in
issue which are redetermined annually. The next redetermination takes place in
June 2023, with renewed bonds (or other arrangements, if applicable) to be put
in place by the end of 2023. As part of the going concern assessment the
Directors sought advice from surety bond brokers over the Group's ability to
renew surety bonds given the combined impact of higher tax and inflation rates
adversely impacting the calculation of the amount of security required. Based
on the advice received, the Directors are of the view that the surety market
will continue to provide security up to the current DSA provisions and those
required in the foreseeable future.
Various downside scenarios were also analysed, including reasonably possible
commodity price and production downsides, and a scenario where the Group has
to fully cover its estimated DSA obligations in cash. Individually these
scenarios demonstrated an ability to meet the bond covenants and have
sufficient cash available to continue in operational existence in the going
concern period. If the estimated DSA obligations were required to be fully
covered in cash and either the commodity price or production downside
scenarios realised, then it is estimated that, with no mitigating activities
undertaken, the Group may fall below its liquidity covenants in or around
November 2024. A reverse stress test was also performed, which showed that
either a reduction in sales volume or price of approximately 45% (compared to
the base case forecast) for the remainder of the going concern period, with
all other factors held constant, would result in the liquidity covenants
similarly being breached in November 2024. However, as these potential
breaches are forecast to occur shortly prior to the receipt of a material
Norwegian cash tax rebate anticipated in December 2024, the Group is of the
opinion that, should this combination downside scenario crystallise, it would
be able to manage its liquidity position and avoid any breach via temporary
working capital management. As outlined above, the Group believes the
possibility that it will be unable to renew its surety bonds on the same basis
as currently posted to be unlikely.
As a result of the above, the Directors have concluded that there is a
reasonable expectation that the Group has adequate resources to continue in
operational existence throughout the going concern period, and therefore the
going concern basis is adopted in the preparation of these financial
statements.
1.3 Significant events and changes in the year
The financial performance and position of the group was significantly affected
by the following events and changes during the year:
· The acquisition of a 20% interest in the Greater Laggan Area
(GLA) producing gas fields and associated infrastructure alongside various
interests in certain other exploration licences, including a 25% interest in
the Benriach prospect, from TotalEnergies E&P UK Limited in July 2022,
arising in the recognition of, among other assets and liabilities, €223.6
million of fixed assets, €115.0 million of decommissioning liabilities and
€10.9 million of goodwill (note 2.10);
· A significant increase in average realised sales prices and
therefore significantly higher revenue as compared to the prior period due to
increased commodity prices (note 2.1);
· The recognition of €44.3 million of impairment charges to
exploration and evaluation assets in the Netherlands segment following changes
to the tax regimes making it more uncertain that the carrying value of those
assets could be recovered through successful development (note 2.8);
· An increase to the unit-of-production depletion charge rate in
the Netherlands segment following a revision to the reserves base for
depreciation purposes (note 2.6);
· Gains of €27.0 million recognised in the income statement
relating changes in contingent consideration payable (note 2.10.2), comprising
a €19.5 million fair value gain relating to actualisation of the GLA
acquisition payment linked to gas price, and a release of €7.5 million
relating to the M10/M11 licence from the Tulip Oil acquisition (the
corresponding asset for which was also fully impaired in the period);
· A tax charge of €71.6 million arising from the introduction of
the Energy Profits Levy (EPL) in the UK (note 6.2);
· A tax charge of €46.9 million arising from the retrospective
imposition of the Solidarity Contribution Tax in the Netherlands (note 6.1 and
6.3);
· A capital reduction resulting in an increase to retained earnings
of €50 million, a reduction to share premium of €35 million and a
reduction to the merger reserve of €14 million (note 5.3); and
· A capital reorganisation (being the incorporation of Kistos
Holdings plc as the new controlling party of the Group) resulting in an
increase in the merger reserve to €141.7 million and creation of a capital
reorganisation reserve (note 5.3).
1.4 Foreign currencies and translation
Items included in the financial statements of each of the Group's entities are
measured using the currency of the primary economic environment in which each
entity operates (the functional currency). Transactions in currencies other
than the functional currency are translated to the entity's functional
currency at the foreign exchange rates at the date of the transactions.
Foreign exchange gains and losses resulting from the settlement of monetary
assets and liabilities denominated in foreign currencies are recognised in the
income statement. All UK-incorporated entities in the Group, including Kistos
Holdings plc, have a functional currency of pounds Sterling (GBP). All
Dutch-incorporated entities have a functional currency of euros (EUR).
These financial statements are presented in EUR, a currency different to the
functional currency of the reporting entity (which is GBP), as a significant
proportion of the consolidated results are attributable to subsidiaries whose
functional currency is EUR, and the debt issued by members of the Group is
denominated in EUR.
All amounts have been rounded to the nearest thousand EUR, unless otherwise
stated.
The results and balance sheet of all the Group entities that have a functional
currency different from the presentation currency are translated into the
presentation currency as follows:
· assets and liabilities for each balance sheet presented are
translated at the closing rate at the date of that balance sheet (except for
long-term assets and liabilities which are translated at the historical rate);
· income and expenses for each income statement are translated at
average exchange rates for the period; and
· all resulting exchange differences are recognised in 'Other
comprehensive income'.
Goodwill and fair value adjustments arising on the acquisition of a foreign
operation are treated as assets and liabilities of the foreign operation and
translated at the closing rate.
1.5 New and amended accounting standards adopted by the Group
The Group has applied the following new accounting standards, amendments and
interpretations for the first time:
· Property, Plant and Equipment: Proceeds before intended use -
Amendments to IAS 16;
· Reference to the Conceptual Framework - Amendments to IFRS 3;
· Onerous Contracts - Cost of Fulfilling a Contract (Amendments to
IAS 37); and
· Annual Improvements to IFRS Standards 2018-2020.
The adoption of the changes and amendments above has not had any material
impact on the disclosure or on the amounts reported in the financial
statements, nor are they expected to significantly affect future periods.
1.6 New and amended accounting standards not yet adopted
A number of other new and amended accounting standards and interpretations
have been published that are not mandatory for the reporting period ended 31
December 2022, nor have they been early adopted. These standards and
interpretations are not expected to have a material impact on the consolidated
financial statements.
1.7 Accounting judgements and major sources of estimation uncertainty
In the application of the Group's accounting policies, the Directors are
required to make judgements, estimates and assumptions about the carrying
amounts of assets and liabilities that are not readily apparent from other
sources. The estimates and associated assumptions are based on historical
experience and other factors that are considered to be relevant. Actual
results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognised in the period in which the
estimate is revised if the revision affects only the period, or in the period
of the revision and future periods if the revision affects both current and
future periods.
The following are critical judgements, apart from those involving estimations
(which are dealt with separately below), that the Directors have made in the
process of applying the Group's accounting policies and that have the most
significant effects on the amounts recognised in the financial statements:
· acquisition accounting - definition of a business and assessment
of control (note 2.10);
· identification of impairment indicators for fixed assets and
goodwill (note 2.8); and
· uncertain tax positions (note 6.3).
The assumptions concerning the future, and other major sources of estimation
uncertainty at the balance sheet date that may have a significant risk of
causing a material adjustment to the carrying amount of assets and liabilities
within the next financial year, are:
· estimated future cash flows from assets used as basis for
impairment testing for fixed assets and goodwill (note 2.8);
· estimated quantity of reserves and contingent resources (section
2); and
· the estimated cost for abandonment provisions (note 2.5).
The presumption of going concern is no longer deemed a significant judgement
due to the strong cash balances of the Group and projected significant
headroom over its debt covenants even taking into account downside
sensitivities on commodity prices and production rates. See note 1.2 for
further analysis of the assessment of going concern.
1.7.1 Impact of climate change and energy transition on accounting judgements
and major sources of estimation uncertainty
The Directors have taken into account climate change and the desire by
national and international bodies to transition towards a lower carbon
economy were considered in preparing these consolidated Financial Statements.
Most immediately, the energy transition is likely to impact future gas and oil
prices which in turn may affect the recoverable amount of the Group's assets.
The estimate of future cash flows from assets, which includes management's
best estimate of future oil prices, is considered a key source of estimation
uncertainty. Further details of the key price assumptions are outlined in note
2.8, including sensitivity analysis outlining the amount by which commodity
prices would need to change to reduce the recoverable amount to the carrying
amount of the assets being tested. Under current forecasts assuming the assets
in their current condition, the Group's oil and gas assets are likely to be
fully depreciated within five years, during which timeframe it is expected
that global demand for gas will remain robust. Accordingly, the impact of
climate change on expected useful lives of the Group's current assets is not
considered to be a significant judgement or estimate. In addition to oil and
gas assets, climate change and energy transition could adversely impact the
future development or viability of intangible exploration and evaluation
assets. The existence of impairment triggers for such assets under IFRS 6 is
considered a critical accounting judgement (see note 2.8).
Section 2 Gas and oil operations
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
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
Geographical region
Netherlands UK Total Total
Sales of liquids - - - 108
Sales of natural gas 285,053 126,459 411,512 89,520
Total revenue from contracts with customers 285,053 126,459 411,512 89,628
All revenue in the prior period was attributable to the Netherlands region.
2.2 Segmental information
2.2.1 Segments and principal activities
The performance of the Group is monitored by the Executive Directors
(comprising the Executive Chairman, Chief Executive Officer and Chief
Financial Officer) on a geographical basis, and therefore there are now two
reportable segments identified for the Group's business:
· Netherlands: Comprising the production and sale of gas and other
hydrocarbons from the Q10-A field, and the costs associated with exploration,
appraisal and development of other Dutch licences; and
· UK: Comprising the production and sale of gas and other
hydrocarbons from the Group's interest in the GLA, and the costs associated
with exploration, appraisal and development of other licences in the UK North
Sea. This segment was created during the year, following the acquisition
completed in July 2022 (note 2.10).
The key measure of performance used by the Executive Directors to review
segment performance is Adjusted EBITDA (note 2.2.2). They also receive
disaggregated information concerning revenue, income tax charge and capital
expenditure by segment on a regular basis. Information about measures of total
assets and liabilities by segment is not regularly provided to the Executive
Directors. Transactions between segments are measured on the same basis as
transactions with third parties and eliminate on consolidation.
2.2.2 Adjusted EBITDA
The Executive Directors use Adjusted EBITDA to assess the performance of the
operating segments. Adjusted EBITDA is a non-IFRS measure, which management
believe is a useful metric as it provides additional useful information on
performance and trends. Adjusted EBITDA is not defined in IFRS or other
accounting standards, and therefore may not be comparable with similarly
described or defined measures reported by other companies. It is not intended
to be a substitute for, or superior to, any nearest equivalent IFRS measure.
Adjusted EBITDA excludes the effects of significant items of income and
expenditure which may have an impact on the quality of earnings such as
provisions for impairment, other non-cash charges such as depreciation and
share-based payment expense, transaction costs and development expenditure. A
reconciliation of Adjusted EBITDA by segment to profit before tax, the nearest
equivalent IFRS measure, is presented below.
€'000 Note Year ended 14 October 2020 to 31 December 2021
31 December 2022
Netherlands Adjusted EBITDA 270,626 81,211
UK Adjusted EBITDA 112,899 --
Head office costs and eliminations (3,510) (2,350)
Group Adjusted EBITDA 380,015 78,861
Development expenses 2.4 (1,752) (4,456)
Share-based payment expense 3.4 (538) -
Depreciation and amortisation 2.6 (83,234) (13,277)
Impairments 2.8 (44,547) (121,036)
Transaction costs (681) (2,864)
Change in fair value and releases of contingent consideration 2.10.2 26,993 -
Operating profit/(loss) 276,256 (62,772)
Net finance costs (22,131) (11,085)
Profit/(loss) before tax 254,125 (73,857)
Transaction costs in the current period include:
· costs relating to the GLA acquisition; and
· costs incurred on a proposed transaction with Serica Energy plc,
which did not proceed.
Transaction costs in the prior period relate to those costs incurred on the
Tulip Oil acquisition.
2.2.3 Other segmental disclosures
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).
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
Netherlands UK Total Total
Segment revenue 285,748 125,908 411,656 89,628
Inter-segment revenue (144) - (144) -
Revenue from external customers 285,604 125,908 411,512 89,628
All Netherlands segment external revenue in the current and prior period was
derived from a single external customer. All UK segment revenue in the current
year was derived from another single external customer.
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
Income tax charge/(credit):
Netherlands 135,414 25,963
UK 121,740 -
Unallocated and consolidation adjustments (28,990) (59,712)
Total 228,164 (33,749)
2.3 Production costs
Production costs include:
· the export of the gas produced from the Q10-A platform to a
third-party platform, P15-D, including treatment tariff, compression tariff,
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).
€'000 Abandonment provision
At 1 January 2022 17,176
Acquisitions 115,004
Accretion expense 1,875
Changes in estimates to provisions (1,877)
Utilisation (2,319)
Effect of change to discount rate (3,729)
Foreign exchange differences (42)
At 31 December 2022 126,088
Of which:
Current 2,585
Non-current 123,503
Total 126,088
Abandonment provisions comprise:
· In the Netherlands, the Group's share of the estimated cost of
abandoning the producing Q10-A wells, decommissioning the associated
infrastructure, plugging and abandoning the currently suspended Q11-B well,
and removal and restoration of certain onshore pipelines and corresponding
land from historic assets.
· In the UK, the Group's share of the estimated cost of plugging
and abandoning the producing and suspended Laggan, Tormore, Edradour and
Glenlivet wells, removal of the associated subsea infrastructure, and
demolition of the Shetland Gas Plant and restoration of the land upon which
the plant is constructed.
The abandonment of the Q10-A wells and associated infrastructure is expected
to take place between eight and nine years from the balance sheet date, in
2025 for the Q11-B well (based on the regulatory requirement to abandon the
well by that time as, at the balance sheet date, no extension of the licence
or production consent had been concluded) and within one year for the onshore
pipelines and land restoration. The removal and restoration of onshore
pipelines and corresponding land is expected to take place within one year of
the balance sheet date.
The abandonment of the UK fields and associated infrastructure is expected to
take place between 5 and fourteen years from 31 December 2022 based on current
production and commodity price forecasts and sanctioned development plans.
The utilisation of provisions in the period relates to the onshore abandonment
of the onshore Donkerbroek-Hemrik location.
Abandonment provisions are initially estimated in nominal terms, based on
management's assessment of publicly available economic forecasts and
determined using an inflation rate of 2.5% (2021: 1.0%) and a discount rate of
2.5% to 3.5% (2021: 0.5%). The changes in estimates to provisions arises
primarily as a result of the increased inflation rate assumed.
The Group has in issue €27.4 million of surety bonds as at 31 December 2022
(2021: nil) to cover its obligations under Decommissioning Security Agreements
(DSAs) for the GLA fields and infrastructure. The amount of the bonds required
is re-assessed each year, changing in line with estimated post-tax cash flows
from the assets, revisions to the abandonment cost, inflation rates, discount
rates and other inputs defined in the DSAs.
2.6 Property, plant and equipment
€'000 Assets under construction Production facilities and wells Other Total
Cost
At 14 October 2020 - - - -
Acquisition of business (note 2.10.1) 1,227 174,156 142 175,525
Additions 9,187 692 183 10,062
Other - 151 - 151
Reclassifications (10,414) 10,414 - -
At 31 December 2021 - 185,413 325 185,738
Acquisition of business (note 2.10) - 189,790 - 189,790
Additions 7,401 3,885 1,416 12,702
Disposals - (11,922) (58) (11,980)
Foreign exchange differences and other movements - (8,435) - (8,435)
At 31 December 2022 7,401 358,731 1,683 367,815
Accumulated depreciation and impairment
At 14 October 2020 - - - -
Depreciation charge for the period - (13,161) (116) (13,277)
Provision for impairment (note 2.8) - (1,234) - (1,234)
At 31 December 2021 - (14,395) (116) (14,511)
Depreciation charge for the period - (83,023) (211) (83,234)
Foreign exchange differences - 734 3 737
Disposals - 11,922 31 11,953
Provision for impairment (note 2.8) - (286) - (286)
At 31 December 2022 - (85,048) (293) (85,341)
Net book value at 31 December 2021 - 171,018 209 171,227
Net book value at 31 December 2022 7,401 273,683 1,390 282,474
'Assets under construction' relates to wells drilled but not yet producing.
The 'Other' category includes office and IT equipment, including assets
(primarily office leases) held as right-of-use assets (note 5.2).
'Disposals' represent the removal of fully depreciated assets following the
conclusion of the abandonment campaign on the location Donkerbroek Hemrik in
Kistos NL1.
2.7 Intangible assets
€'000 Goodwill Exploration and evaluation assets Total
Cost
At 14 October 2020 - - -
Acquisition of business (note 2.10.1) 7,000 144,856 151,856
Additions - 13,717 13,717
At 31 December 2021 7,000 158,573 165,573
Acquisition of business (note 2.10) 10,913 32,923 43,836
Additions - 8,660 8,660
Other - 245 245
At 31 December 2022 17,913 200,401 218,314
Accumulated amortisation and impairments
At 14 October 2020 - - -
Impairment (7,000) (112,802) (119,802)
At 31 December 2021 (7,000) (112,802) (119,802)
Impairment - (44,261) (44,261)
At 31 December 2022 (7,000) (157,063) (164,063)
Net book value at 31 December 2021 - 45,771 45,771
Net book value at 31 December 2022 10,913 43,338 54,251
Exploration and evaluation assets include the exploration licence portfolio
acquired as part of the GLA acquisition, and the Orion oil prospect on the
Q10-A licence. The Group's licences are outlined in note 2.9.
2.8 Impairment of assets and goodwill
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
€0.3 million relate to a portion of the previously producing A01 well which,
at the balance sheet date, had been partially abandoned in preparation for the
drilling of a side-track.
Impairments of intangible exploration and evaluation assets in the Netherlands
segment of €44.3 million comprise:
- a full impairment of the carrying value attributed to the Q11-B
exploration asset (€26.8 million);
- a full impairment of the carrying value attributed to the Q10-B
exploration asset (€10.0 million); and
- a full impairment of the carrying value attributed to the
M10/M11 exploration asset (€7.5 million).
The Q11-B and Q10-B assets have been impaired due to the scale, manner and
nature of additional taxes introduced by the Dutch tax authorities. These
increased taxes and levies have introduced uncertainty into what was
previously a stable and predictable fiscal regime and, unlike equivalent
measures in the UK, do not incentivise licence holders to invest further by
means of enhanced deductions for capital expenditure. As budgeted spend on
these assets has now been placed on hold pending further clarity on these
measures and whether they are to be extended, and taking into account that
during the previous year's drilling campaign the Q11-B appraisal well failed
to produce gas from its primary target (but did have more successful tests
from the Zechstein and Bunter formations), there is no longer sufficient
certainty over whether the carrying value can be recovered from future
development, therefore the amounts have been impaired in full.
The M10/M11 asset has been impaired because, as at the balance sheet date, the
Group's application to renew the relevant licence had not been successful, and
there is sufficient uncertainty as to whether the Group would be successful in
its appeal and/or re-application. €7.5 million of contingent consideration
payable (which would have crystallised upon confirmation by the Group to the
vendor of the Group's intention to proceed with the exploitation of the
M10/M11 licences by February 2022) has also been derecognised and a
corresponding gain recognised as a separate line in profit and loss (see note
2.10.2).
The imposition of cijns in the Netherlands, and re-assessment of reserves on
the Q10-A field, were considered by management to be impairment triggers for
the Netherlands Production CGU. An impairment test was therefore undertaken,
using a value-in-use method, which demonstrated that the recoverable amount
exceeded the CGU's carrying amount and therefore no impairment charge was
necessary.
An impairment test was also carried out in respect of the UK Production and
Development CGU, with the primary impairment indicator being the introduction,
and subsequent increase and extension of, the Energy Profits Levy (increasing
the effective tax rate applicable on the CGU from 40% at acquisition to 75%).
The recoverable amount of the CGU was determined by assessing the FVLCOD of
the CGU, by way of discounted cash flow projections, in line with how other
market participants would typically value such assets. The valuation is level
3 in the fair value hierarchy due to a number of unobservable inputs used in
the estimate.
The key assumptions used in determining FVLCOD were as follows:
- NBP gas price of 287p/therm in 2023, 218p/therm in 2024 and
138p/therm in 2025 based on independent forecasts and estimates prevailing at
the balance sheet date;
- production rates forecast by the asset operator, with the
expected natural decline consistent with past performance, extending to the
estimated cessation of production date (i.e. no growth rates applied);
- decommissioning liabilities in line with the carrying value of
the provisions at the balance sheet date; and
- a post-tax discount rate of 13% reflecting the specific risks
relating to the segment and geographical region.
The costs of disposal were not considered to be material for the purposes of
the exercise.
The results of the impairment test were that the recoverable amount exceeded
the carrying amount by €86 million. It is estimated that a change to the
following key assumptions would result in the recoverable amount being equal
to the carrying amount:
- a reduction to the forward gas curve of approximately 60%; or
- a reduction to projected production rate of approximately 60%.
2.9 Joint arrangements and licence interests
The Group has the following interests in joint arrangements that management
has assessed as being joint operations. Following acquisition of the GLA
assets, Kistos Energy Limited is the non-operational partner in joint
arrangements with the operator, TotalEnergies E&P UK. Except where
otherwise noted, the interest and status of licences is the same as at the end
of the prior period.
Field or licence Licence owner Licence type Status Interest at 31 December 2022
M10a & 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, P1453(2) Kistos Energy Limited Production Non-operated 20%
and P1678)(4)
Benriach (licences P2411 and P1453(2)) (4) Kistos Energy Limited Exploration Non-operated 25%
Bunnehaven (licence P2415(3)) (4) Kistos Energy Limited Exploration Non-operated 25%
Cardhu (licence P2594) (4) Kistos Energy Limited Exploration Non-operated 20%
Roseisle (licence P2604) (4) Kistos Energy Limited Exploration Non-operated 14%
(1) The Group does not hold the M10/M11 licence at the balance sheet date and
is in the process of appealing the non-renewal of the licence.
(2) Licence P1453 is split into the portion including and excluding the
Benriach area.
(3) In process of being relinquished.
(4) Acquired during the period.
In January 2023, Kistos NL2 B.V. was awarded the P12b, Q13b and Q14
exploration licences where it will act as operator with 60% interest.
2.10 Business combinations
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:
€'000 At acquisition date
Consideration:
Cash 40,047
Contingent consideration 38,029
Total consideration 78,076
Net assets acquired:
Property, plant and equipment 189,790
Exploration and evaluation assets 32,923
Investment in associates 61
Net working capital (3,826)
Abandonment provisions (115,004)
Net deferred tax liability (36,781)
Goodwill 10,913
Net assets acquired 78,076
Goodwill arises primarily from the requirements to recognise deferred tax on
the difference between the fair value and the tax base of the assets acquired.
This fair value uplift is not tax deductible and therefore results in a net
deferred tax liability and corresponding entry to goodwill.
Transaction costs of €0.4 million were incurred, recognised within 'General
and administrative expenses' in the profit and loss account, and within
operating cash flows in the cash flow statement.
The contingent consideration comprises two elements:
· Up to a maximum of $40 million (€39.3 million) payable based on
a formula including GLA gas production and average quoted gas prices through
2022. The fair value of this contingent consideration was assessed to be
€34.9 million at the acquisition date, based on actual gas prices and
production up to the acquisition date, forecast gas production for the balance
of the year and an option pricing model using observable forward gas curves as
at the acquisition date and forecast gas production for the balance of the
year. At the balance sheet date all of the inputs to the contingent
consideration calculation were available, and therefore it has been remeasured
to the final settlement amount of €15.8 million, which was settled in cash
in March 2023. The change in contingent consideration payable was driven
primarily by movements in the gas price during the year as compared to the
forward gas curves at the acquisition date. This contingent consideration has
been classified as level 3 in the fair value hierarchy.
· Upon the successful development of the Benriach area,
consideration of $0.25 per MMBtu of the approved net 2P reserves following
first gas. The fair value of this contingent consideration was assessed by
management to be €3.1 million, estimated based on the operator's P50
estimate of gross recoverable resources (638 Bcf), risk-adjusted to reflect
management's assessment of chances of successful discovery and development,
and discounted to present value based on the earliest estimated time that the
contingent payment could crystallise. As at 31 December 2022, there has been
no change in the amount recognised for the liability other than the interest
accretion expense of €0.1 million (recognised within finance costs). This
contingent consideration has been classified as level 3 in the fair value
hierarchy.
2.10.1 Acquisition in prior period
On 20 May 2021, Kistos plc completed the 100% acquisition of Tulip Oil
Netherlands B.V. (renamed to Kistos NL1) and Tulip Oil Netherlands Offshore
B.V. (renamed to Kistos NL2) for consideration of €155.0 million. The
acquisition consideration, management's assessment of the net assets acquired,
and subsequent goodwill arising were as follows:
€'000 At acquisition date
Consideration:
Cash 124,225
Shares issued in Kistos plc 15,750
Contingent consideration 15,000
Total consideration 154,975
Net assets acquired:
Property, plant and equipment 175,525
Exploration and evaluation assets 144,856
Deferred tax assets 19,477
Cash and cash equivalents 23,529
Net working capital 1,163
Bond debt (85,417)
Abandonment provisions (14,158)
Deferred tax liabilities (117,000)
Goodwill 7,000
Total net assets acquired 154,975
Contingent consideration of €15.0 million payable was recognised on
acquisition, and comprised the following:
· €7.5 million payable by February 2022 upon confirmation by
Kistos of its intention to proceed with exploitation activities in respect of
Vlieland Oil (Orion); and
· €7.5 million payable by February 2022 upon confirmation by
Kistos of its intention to retain ownership of the M10/M11 licences.
The contingent consideration in respect of Orion was paid during the current
year. Contingent consideration relating to M10/M11 has been derecognised in
full because, as at the balance sheet date, the Group had not been successful
in its application to renew the relevant licences. Contingent consideration
relating to the acquisition which was not recognised on the balance sheet is
disclosed in note 7.2.
2.10.2 Movement in contingent consideration payable
The movement of contingent consideration balances is as follows:
€'000 GLA acquisition Tulip Oil acquisition
At 14 October 2020 - -
Recognised on acquisition - 15,000
At 31 December 2021 - 15,000
Recognised on acquisition 38,029 -
Contingent consideration paid - (7,500)
Gain recognised following change in fair value (19,493) -
Accretion expense 153 -
Gain recognised following derecognition - (7,500)
Foreign exchange differences 375 -
At 31 December 2022 19,064 -
2.10.3 Contribution
The GLA acquisition contributed revenue of €125.9 million and a loss after
tax of €20.1 million in the period from acquisition. If the acquisition had
completed on 1 January 2022, consolidated revenue for the Group would have
been €568.4 million. It has been considered impracticable to disclose the
impact to consolidated profit and loss after tax if the acquisition had
completed on 1 January 2022, due to the complexity of remeasuring the fair
value of the acquired assets at 1 January and subsequent impact to
depreciation, the complexity of measuring the contingent consideration payable
at 1 January and subsequent impact to gain or loss on remeasurement, the
combined impact of the above and other factors on the initial deferred tax
liability recognised and subsequent deferred tax charge or credit and the lack
of available information to determine the timing of certain expenditure for
tax and EPL purposes. The impact to Adjusted EBITDA and EBITDA as if the
acquisition had completed on 1 January 2022 is disclosed in Appendix B.
2.11 Commitments
As at the reporting dates, the Group had outstanding contractual capital
commitments as follows:
€'000 31 December 2022 31 December 2021
Contractual commitments to acquire property, plant and equipment 2,553 1,400
Contractual commitments on intangible assets (including commitments on 27,483 -
exploration assets)
Total 30,036 1,400
Section 3 Income statement
3.1 Earnings per share
Year ended 31 December 2022 14 October 2020 to 31 December 2021
Consolidated profit/(loss) for the period, attributable to shareholders of the 25,961 (40,108)
Group (€'000)
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 82,999,732 58,867,726
in calculating diluted earnings per share
Earnings/(loss) per share (€) 0.31 (0.68)
Diluted earnings/(loss) per share (€) 0.31 (0.68)
3.2 General and administrative expenses
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
Salaries and contractors 6,598 3,114
Training, travel and subsistence 229 129
IT and communication 162 105
Professional services 2,657 4,238
Other (including recovery and capitalisation of costs) (220) (160)
Total other operating expenses 9,426 7,426
3.3 Employee benefit expenses
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
Wages and salaries 6,286 2,585
Social security costs 910 272
Equity-settled share-based payments (note 3.4) 538 -
Total employee benefit expenses 7,734 2,857
At the end of the period there were 24 employees (2021: 17 employees) of the
Group (excluding Non-Executive Directors); 16 (2021: 12) in the Netherlands,
two in Germany (2021: nil) and six (2021: five) in the United Kingdom.
The average number of employees in the Group is as follows:
Year ended 31 December 2022 14 October 2020 to 31 December 2021
Technical 14 4
Support 7 3
Management 3 3
Total staff 24 10
3.4 Share-based payment arrangements
During the year, the Group introduced share-based payment schemes for certain
employees, which are outlined below. The total charge in respect of
share-based payments for the year was €0.5 million (2021: nil).
Share option incentive awards (equity-settled)
On 1 February 2022, the Group established a share option programme that
entitles all full-time employees of Kistos plc and Kistos NL2 to purchase
shares of Kistos plc. Under this programme, holders of vested options are
entitled to purchase shares at the option price of the shares once the options
have vested. All options are to be settled by delivery of new shares.
Share option matching awards (equity-settled)
On 1 February 2022, the Group offered certain full-time employees in Kistos
plc and Kistos NL2 to participate in an employee share purchase plan. To
participate in the plan, the employees are required to buy, or already hold,
shares of Kistos plc ('matched shares') with own funds. Under this programme,
holders of vested options are entitled to purchase shares at the option price
of the shares once the options have vested. All options are to be settled by
delivery of new shares.
The key terms and conditions of the arrangements are as follows:
Share-based payment arrangement Grant date Number of shares Vesting conditions Contractual life of options
Incentive awards 14 February 2022 215,382 Employee remains in service during the vesting period. Option vest in equal 10 years
instalments on the first, second and third anniversaries of the awards
Matching awards 25 April 2022 125,690 Employee remains in service during the vesting period and holds the equivalent 10 years
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 £ £2.27 £2.64
Share price at grant date £3.57 £4.14
Exercise price £2.73 £3.43
Expected volatility 49.83% 50.49%
Periods to exercise 10 years 10 years
Expected dividends Not applicable Not applicable
Risk-free interest rate (based on government bonds) 0.44% 1.12%
Expected volatility has been based on an evaluation of historical volatility
of the share price, particularly over the historical period commensurate with
the term between the initial public offering of Kistos plc's shares and the
grant date(s) of the share-based payment programme(s). No expected dividends
were included in the option pricing model as the granting entity has no
history of paying dividends. Based on lack of historical data, it is expected
that all employees remain in place during the scheme and will have a maximum
of 10 years to exercise the options. At 31 December 2022, no employees have
left the employer that participate in the share option programme(s).
Following the capital reorganisation, the terms of the share options were
modified such that once the share options have vested and upon their exercise,
they will be settled in ordinary shares of Kistos Holdings plc instead of
Kistos plc. However, as the reorganisation was an exchange of ordinary shares
in Kistos Holdings plc for those of Kistos plc (with each share having the
same economic and voting rights) it was determined that there was no change to
the fair value of share options as a result of this modification.
Reconciliation of outstanding share options
As at 31 December 2022 the following share options are outstanding, as the
date of the first anniversary has not yet been reached, none of these share
options have been vested. Based on the vesting conditions, requiring at least
three years of service for the full share options awards, the costs of
share-based payments are front-loaded.
Incentive awards Matching awards
Outstanding at 1 January 2022 - -
Share options first anniversary 65,813 38,405
Share options second anniversary 32,907 19,203
Share options third anniversary 21,938 12,802
Outstanding at 31 December 2022 120,658 70,410
Fair value per share € €2.71 €3.13
Upon vesting of the share options and exercise by the employee, the obligation
will be settled by Kistos Holdings plc.
3.5 Interest and other net finance costs
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
Interest income (267) -
Total interest income (267) -
Bond interest payable 10,543 8,900
Bank charges and other interest expense 268 93
Surety bond interest 472 -
Total interest expenses 11,283 8,993
Accretion expense on abandonment provisions and other liabilities (note 2.5 2,028 43
and 2.10.2)
Accretion expense on lease liabilities 42 2
Amortisation of bond costs (note 5.1) 1,062 700
Hedge ineffectiveness recognised in income statement - 625
Net foreign exchange losses/(gains) 1,569 (59)
Loss on bond redemption (note 5.1.1) 6,414 -
Loss on bond modification - 781
Total other net finance costs 11,115 2,092
Total 22,131 11,085
Section 4 Working capital
4.1 Cash and cash equivalents
Cash and cash equivalents consist of bank accounts and restricted cash
balances. The restricted funds at the end of 2021 and 2022 relate to a bank
guarantee for the office lease in The Hague.
€'000 31 December 2022 31 December 2021
Bank accounts 211,958 77,266
Restricted funds 22 22
Cash and cash equivalents 211,980 77,288
4.2 Trade and other receivables
€'000 31 December 2022 31 December 2021
Receivables due from joint operation partner 3,198 3,920
Other receivables 1,594 2,014
Prepayments 679 163
VAT receivable 1,129 2,342
Total other receivables 6,600 8,439
4.2.1 Accrued income
The accrued income balance of €48.0 million (2021: €40.3 million)
represents amounts due to the Group in respect of gas sales revenue which had
not been invoiced at the balance sheet date. All accrued income amounts had
been invoiced and collected in full within one month of the corresponding
reporting date.
Information about the Company's exposure to credit risk and impairment losses
for other short-term receivables is included in note 4.6.
4.3 Trade payables and accruals
€'000 31 December 2022 31 December 2021
Trade payables 7,271 9,018
Accruals 12,101 14,461
Total trade payables and accruals 19,372 23,479
Trade payables are unsecured and generally paid within 30 days. Accrued
expenses are also unsecured and represents estimates of expenses incurred but
where no invoice has yet been received. The carrying value of trade payables
and other accrued expenses are considered to be fair value given their
short-term nature.
4.4 Other liabilities
€'000 31 December 2022 31 December 2021
Bond interest payable 831 1,854
Hedge liability --- 11,781
Salary and salary-related liabilities 202 97
Contingent consideration (note 2.10.2) 15,796 15,000
Joint operator payable 1,945 -
Lease liabilities 282 91
Other liabilities - current 19,056 28,823
Contingent consideration 3,268 -
Other loans - 31
Lease liabilities 929 -
Other liabilities - non-current 4,197 31
The interest on bond debt is payable semi-annually. The hedge liability
represented the fair value liability in respect of the cash flow hedge for the
remaining period of the gas price hedge contract. As at 31 December 2022 the
hedge liability is nil, as no hedges are in place in respect of future
production.
4.5 Inventory
€'000 31 December 2022 31 December 2021
Spares and supplies 3,896 775
Crude oil and natural gas liquids 5,792 127
Total inventory 9,688 902
No inventory was recognised as an expense in the current or prior year. The
movement in inventory net realisable value provisions amounted to a charge of
€0.8 million (2021: nil).
4.6 Financial instruments and financial risk management
4.6.1 Financial risk management objectives
The Group is exposed to a variety of risks including commodity price risk,
interest rate risk, credit risk, foreign currency risk and liquidity risk. The
use of derivative financial instruments is governed by the Group's policies
approved by the Kistos Board. Compliance with policies and exposure limits is
monitored and reviewed internally on a regular basis. The Group does not enter
into or trade financial instruments, including derivatives, for
speculative purposes.
4.6.2 Financial assets and liabilities carried at fair value
The following table shows the fair values of financial liabilities which are
carried at fair value, including their levels in the fair value hierarchy. The
Group holds no financial assets recognised and measured at fair value.
€'000 Level 1 Level 2 Level 3 Total
Financial liabilities
Contingent consideration - GLA acquisition - - 19,064 19,064
Total at 31 December 2022 - - 19,064 19,064
Contingent consideration - Tulip Oil acquisition - - 15,000 15,000
Hedging derivatives - - 11,781 11,781
Total at 31 December 2021 - - 26,781 26,781
4.6.3 Risk management framework
The Kistos Board has overall responsibility for the establishment and
oversight of the Group's risk management framework. The Kistos Board is
responsible for developing and monitoring the Group's risk management
policies.
The Group's risk management policies are established to identify and analyse
the risks faced by the Group, to set appropriate risk limits and controls but
also to monitor risks and adherence to limits. Risk management policies and
systems are reviewed when needed to reflect changes in market conditions and
the Group's activities. The Group aims to develop a disciplined and
constructive control environment in which all employees understand their roles
and obligations.
The Audit Committee oversees how management monitors compliance with the
Group's risk management policies and procedures and reviews the adequacy of
the risk management framework in relation to the risks faced by the Group.
4.6.4 Market risk
Market risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in market prices.
Market risk for the Group has been assessed as comprising foreign exchange
risk, interest rate risk and other commodity price risk.
Currency risk
Currency risk is the risk that fair value or future cash flows of a financial
instrument will fluctuate because of changes in foreign exchange rates.
Entities within the Group undertake transactions in currencies other than
their functional currency, which gives rise to transactional currency risk.
The Group manages this risk to an extent by holding certain amounts of cash in
currencies other than the entity's functional currency to act as an economic
hedge against foreign exchange movements. From time to time, the Group may use
instruments or derivatives to hedge specific future foreign currency payments
or receipts; however, no such transactions were entered into during the
current or prior period.
As at 31 December 2022, 49% of the Group's cash and cash equivalents was held
in EUR (31 December 2021: 60%).
A reasonably possible strengthening or weakening of GBP at 31 December 2022
would have affected the measurement of monetary items denominated in a foreign
currency and affected equity and profit or loss by the amounts shown below.
This analysis assumes that all other variables, in particular interest rates,
remain constant, and ignores any impact of forecast sales and/or expenses. The
exposure to other foreign currency movements is not material.
€'000 Profit or loss Equity, net of tax
31 December 2022 Strengthening Weakening Strengthening Weakening
GBP (10% movement) 10,499 (10,499) 1,073 (1,073)
Interest rate risk
Interest rate risk is the risk that the fair value of future cash flows of a
financial instrument will fluctuate because of changes in market interest
rates.
The Group is exposed to interest rate movements through its cash and cash
equivalents deposits which earn (and, where interest rates are below zero, are
charged) interest at variable interest rates.
The Group's borrowings carry fixed rates of interest (note 5.1) and thus there
is no interest rate exposure thereon.
For the year ended 31 December 2022, it is estimated that a 1% increase in
interest rates would have increased the Group's profit after tax by
approximately €0.2 million, and a 1% decrease would have reduced the Group's
profit after tax by approximately €0.2 million. This sensitivity has been
calculated on the assumption that the amount of cash and cash equivalents on
the Group's interest-bearing accounts at the balance sheet date had been in
place for the whole year. The impact on equity would be the same as the impact
on profit after tax.
Other price risks - commodity price risk
Commodity risk predominantly arises from the sale of natural gas from the
Group's interest in the Q10-A and GLA fields, as the price realised from the
sale of natural gas is determined primarily by reference to quoted market
prices on the day and/or month of delivery.
The Group has used derivatives to mitigate the commodity price risk associated
with its underlying oil and gas revenues. Where such transactions are carried
out, they are done based on the Company's guidelines.
In 2021, Kistos NL2 hedged monthly production from the Q10-A (being the hedged
item) at an amount of 100,000 MWh per month at a price of €25/MWh (being the
hedged instrument) for the nine-month period from July 2021 to March 2022.
Kistos NL2 engaged in this cash flow hedge to cover the potential volatility
of the gas price and the impact that this may have on the concurrent capital
expenditure programme. In the current period, the hedge was effective (2021:
€0.6 million of hedge ineffectiveness was recognised within net finance
costs).
As at 31 December 2022, the Group had no commodity price hedging arrangements
in place.
The Group enters into other commodity contracts (such as purchases of carbon
emission allowances, fuel and chemicals) in the normal course of business,
which are not derivatives, and are recognised at cost when the transactions
occur.
Credit risk
Credit risk is the risk that the Group will suffer a financial loss as a
result of another party failing to discharge an obligation and predominantly
arises from cash and other liquid investments deposited with banks and
financial institutions, receivables from the sale of natural gas and other
hydrocarbons, and receivables outstanding from its joint operation partner.
The Group has a credit policy that governs the management of credit risk,
including the establishment of counterparty credit limits and specific
transaction approvals. The Group's oil and gas sales are predominantly made to
international oil market participants including the oil majors, trading houses
and refineries. Joint operators are predominantly international major oil and
gas market participants and entities wholly owned by the Dutch state. Material
counterparty evaluations are conducted utilising international credit rating
agency and financial assessments. Where considered appropriate, security in
the form of trade finance instruments from financial institutions with
appropriate credit ratings, such as letters of credit, guarantees and credit
insurance, are obtained to mitigate the risks.
The Group held cash and cash equivalents of €212.0 million as at 31 December
2022 (2021: €77.3 million). As at 31 December 2022, 99% of the Group's cash
and cash equivalents are held with bank and financial institution
counterparties which have an investment grade credit rating.
Impairment on cash and cash equivalents has been measured on a 12-month
expected loss basis and reflects the short maturities of the exposures. The
Group considers that its cash and cash equivalents have low credit risk based
on external credit ratings of the counterparties.
The carrying values of cash and cash equivalents and trade and other
receivables represent the Group's maximum exposure to credit risk at year end,
as the Group has not recognised an allowance for credit losses in the current
or prior period. The Group has no material financial assets that are past due.
4.6.6 Liquidity risk
Liquidity risk is the risk that the Group will encounter difficulty in meeting
obligations associated with its financial liabilities that are settled by
delivering cash or other financial assets.
The Group manages its liquidity risk using both short- and long-term cash flow
projections, supplemented by debt financing plans and active portfolio
management. Ultimate responsibility for liquidity risk management rests with
the Kistos Board, which has established an appropriate liquidity risk
management framework covering the Group's short-, medium- and long-term
funding and liquidity management requirements.
Cash forecasts are regularly produced, and sensitivities run for different
scenarios including, but not limited to, changes in commodity prices,
different production rates from the Group's producing assets and delays to
development projects. In addition to the Group's operating cash flows,
portfolio management opportunities are reviewed to potentially enhance the
financial capability and flexibility of the Group.
The Group's financial liabilities comprise trade payables (note 4.3), other
liabilities (note 4.4) and bond debt (note 5.1). The maturity analysis of
financial liabilities is shown in note 4.7.
In addition to the amounts held on balance sheet, the Group has in issue
€27.4 million of surety bonds as at 31 December 2022 (2021: nil) to cover
its obligations under Decommissioning Security Agreements (DSAs) for the GLA
fields and infrastructure. Should the Group be in default under the DSAs
resulting in the bond provider being required to pay out on those bonds, the
Group would be required to indemnify the providers by paying cash to cover
their liability. If the surety market were to deteriorate such that the Group
is unable to renew its bonds, the various DSAs would require the Group to post
cash into trust the equivalent value.
4.7 Maturity analysis of financial liabilities
The maturity analysis of contractual undiscounted cash flows for
non-derivative financial liabilities is as follows:
€'000 Within 3 months 3 months to 1 year 1-5 More than 5 years Total
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
€'000 €90 million bond €60 million bond Bond costs Total
Opening balance - - - -
Acquisition of business (note 2.10.1) 86,497 - (1,080) 85,417
Proceeds from bond issue 3,000 60,000 - 63,000
Transaction costs - - (2,588) (2,588)
Amortisation of bond costs - - 700 700
Interest 893 - - 893
Modification of bond terms (2,348) - - (2,348)
At 31 December 2021 88,042 60,000 (2,968) 145,074
Amortisation of bond costs - - 1,062 1,062
Interest 23 - - 23
Derecognition on repurchase (65,359) - - (65,359)
At 31 December 2022 22,706 60,000 (1,906) 80,800
During 2021, Kistos NL2 refinanced an existing €87 million bond with a new
€90 million bond, denominated in EUR with a tenor from May 2021 to November
2024. Interest is paid on a semi-annual basis.
Following the acquisition of Kistos NL1 and Kistos NL2 in 2021, a new €60
million bond was issued by Kistos NL2 that runs from May 2021 to May 2026,
denominated in EUR with an interest rate of 9.15% per annum. Interest is paid
on a semi-annual basis. Kistos NL1 and Kistos plc are guarantors. Each
guarantor irrevocably, unconditionally, jointly and severally:
· guarantees to the bond trustee the punctual performance by Kistos
NL2 of all obligations related to the bonds;
· agrees to make payment to the bond trustee on request in the
event of non-payment by Kistos NL2, together with any default interest; and
· indemnifies the Bond Trustee against any cost, loss or liability
incurred in respect of the obligations of Kistos NL2.
Kistos NL2 has issued a security in favour of the bond trustee over its assets
for both bonds, including a pledge over all intercompany receivables between
Kistos NL2 and Kistos NL1 and Kistos plc. In addition, a Netherlands Pledge
has been provided to the bond trustee covering all receivables of Kistos NL2
and Kistos plc.
31 December 2022 31 December 2021
€'000 Currency Nominal interest rate Year of maturity Face value Carrying amount Face value Carrying amount
€90 million bond € 8.75% 2024 21,572 22,706 90,000 88,042
€60 million bond € 9.15% 2026 60,000 60,000 60,000 60,000
Total 81,572 82,706 150,000 148,042
The face value of the 8.75% 2024 bonds as at balance sheet date is presented
net of €21.6 million of bonds repurchased (but not cancelled).
The fair value of the non-current borrowings is €85.4 million as at 31
December 2022, based on quoted prices available. They are classified as level
1 fair values in the fair value hierarchy as they are listed on the Oslo
Børs.
5.1.1 Repurchase of bonds
During 2022, the Group repurchased €68.4 million in nominal value of its
€90 million bonds at an average price of 104.9%. Although the bonds cannot
be cancelled, the liability relating to the repurchased amount has been
treated as being extinguished, and a loss on repurchase of €6.4 million has
been recognised in the income statement due to the bonds being repurchased at
a premium.
The net loss on repurchase of the bonds is reconciled as follows:
€'000
Total cash consideration paid 73,942
Less: settlement of accrued interest (2,169)
Cash consideration paid for repurchase of bond principal 71,773
Carrying value of bond derecognised (65,359)
Loss on repurchase of bond 6,414
5.1.2 Covenants
€90 million bond Requirement Effective date
Issuer (Kistos NL2)
Minimum liquidity 10,000,000 At all times
Maximum leverage ratio 2.50 From and including 1 January 2022 tested at 30 June and 31 December
Group (Kistos consolidated)
Minimum liquidity 20,000,000 At all times
Maximum leverage ratio 3.50 From and including 30 June 2022 and 31 December
€60 million bond Requirement Effective date
Issuer (Kistos NL2)
Minimum liquidity 10,000,000 At all times
Maximum leverage ratio 2.50 From and including 30 June 2022 and 31 December
Group (Kistos consolidated)
Minimum liquidity 20,000,000 At all times
Maximum leverage ratio 3.50 From and including 30 June 2022 and 31 December
During 2022 and 2021, Kistos NL2 and Kistos plc complied with the minimum
liquidity covenant at all times. On 31 December 2022, the Group had a leverage
ratio of (4.23), calculated as follows:
Covenant calculation 2022
Group pro forma EBITDA for the year 2022 (Appendix B1) 541,224
Borrowings 82,706
Lease liabilities (note 5.2) 1,211
Cash and cash equivalents (note 4.1) (211,980)
Net (cash)/debt for leverage ratio test at 31 December 2022 (128,063)
Leverage ratio (4.23)
5.2 Leases
€'000 31 December 2022 31 December 2021
Right-of-use assets
Offices 1,181 91
Other 46 -
Total 1,227 91
Lease liabilities
Current 929 91
Non-current 282 -
Total 1,211 91
Lease liabilities are included within 'other liabilities' on the balance
sheet, and right-of-use assets are included within the 'other' underlying
class of property, plant and equipment.
The total amount of depreciation charged in respect of right-of-use assets was
€180 thousand (2021: €90 thousand). The total cash outflow for leases was
€181 thousand (2021: €98 thousand). Expenses relating to low-value and
short-term leases was not material.
During 2022, additions of €1.3 million were made to right-of-use assets
(2021: not material), primarily relating to the lease of the Group's new head
office in London.
5.3 Share capital, share premium and other capital reserves
The movements in ordinary shares and other transactions impacting share
capital, share premium and the merger and capital reorganisation reserve are
as follows:
Number of shares Share capital Share premium Merger reserve Capital reorganisation reserve (€'000)
(€'000)
(€'000)
(€'000)
Issue of shares 10 November 2020 8,500,000 987 3,949 - -
Issue of shares 25 November 2020 31,750,000 3,689 33,192 - -
Issue of shares 20 May 2021 42,613,743 4,951 57,040 14,734 -
At 31 December 2021 82,863,743 9,627 94,181 14,734 -
Issue and cancellation of bonus shares - - 14,734 (14,734) -
Capital reduction - - (50,000) - -
Capital reorganisation - (163) (58,915) 140,105 (80,995)
At 31 December 2022 82,863,743 9,464 - 140,105 (80,995)
Ordinary shares have a nominal value of £0.10 per share. The Group's policy
is to manage a strong capital base so as to manage investor, creditor and
market confidence, and to sustain growth of the business. Management monitors
its return on capital. There are currently no covenants related to the equity
of the Group.
Following approval by the Group's shareholders at the Annual General Meeting
in June 2022 and subsequent sanction by the Court in October 2022, the full
balance of the merger reserve in Kistos plc was allotted to share premium by
means of a bonus share issue and cancellation. A capital reduction was then
undertaken to reduce the share premium account of Kistos plc by €50 million
with the corresponding credit to retained earnings. These transactions were
undertaken in order to increase the distributable reserves of Kistos plc, the
parent company of the consolidated group at the time.
In December 2022, the Group's shareholders and the High Court of Justice of
England and Wales sanctioned a scheme of arrangement whereby Kistos Holdings
plc, a newly incorporated entity, became the new ultimate parent company of
the Group with shareholders receiving one Kistos Holdings plc share for each
Kistos plc share held.
The share premium reserve represented amounts paid up on ordinary shares in
excess of their nominal value. Following the capital reorganisation, the share
premium account reflects that of Kistos Holdings plc, which is nil.
The merger reserve represented the difference between the value of shares in
Kistos plc issued as part of the total consideration of the acquisition of
Kistos NL1 and the nominal value per share. Following the capital
reorganisation, the merger reserve now represents the merger reserve of Kistos
Holdings plc, which is the difference between the amount at which the
investment in Kistos plc was recorded and the aggregate nominal value of the
shares in Kistos Holdings plc issued.
The capital reorganisation reserve arising on consolidation represents the
difference between the equity structure of Kistos Holdings plc (as the new
parent company of the Group) and the equity structure of Kistos plc (as the
parent company of the Group) following the scheme of arrangement.
5.4 Hedge reserve
€'000 31 December 2022 31 December 2021
Balance at beginning of the period (5,890) -
Cost of hedging deferred and recognised in OCI 11,781 (11,781)
Deferred tax on hedge reserve in OCI (5,891) 5,891
Balance at end of the period - (5,890)
The hedging reserve represents the change in value of the hedged items
(production) discounted cash flows at the forward gas prices curve between
inception date, year end and fixed hedged instrument (100,000 MWh of
production) discounted cash flow. Amounts that are effective and realised have
been taken into the profit and loss account within gas sales (revenue). During
2022, no hedge ineffectiveness has arisen (2021: €0.6 million). The hedge
reserve has been taxed at an effective rate of 50%.
Kistos NL2 held the following cash flow hedge during 2022:
Volume (MWh) Price Period of hedge
Cash flow hedge 300,000 €25 MWh Jan-Mar 22
The hedge was equally distributed over each month at 100,000 MWh. As at 31
December 2022, all hedges had expired.
5.5 Translation reserve
The translation reserve comprises all foreign currency differences arising
from the translation of the financial statements of foreign operations, as
well as the effective portion of any foreign currency differences arising from
hedges of a net investment in a foreign operation.
5.6 Share-based payment reserve
The share-based payment reserve relates to share-based payment programmes
introduced during 2022 to all full-time employees of Kistos plc and Kistos NL2
B.V. The obligation will be settled by Kistos Holdings plc upon exercise of
the share options by the employees. The corresponding entry to the share-based
payment reserve is the charge of share-based payment expense (note 3.4).
Section 6 Tax
6.1 Tax charge or credit for the period
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
Current tax
Current tax expense for current year 195,531 14,091
Total current tax 195,531 14,091
Deferred tax
Decrease in deferred tax assets 7,039 11,872
Increase/(decrease) in deferred tax liabilities 25,594 (59,712)
Total deferred tax 32,633 (47,840)
Tax charge/(credit) 228,164 (33,749)
The income tax charge or credit for the period can be reconciled to the
accounting profit/(loss) as follows:
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
Profit/(loss) before taxes 254,125 (73,857)
Income tax (charge)/credit calculated at the domestic tax rate applicable to (142,880) 36,929
entity (2021: calculated at 50%)
Investment allowances and other enhanced deductions 7,471 2,239
Income and expenditure not taxable or deductible 21,799 -
Difference in tax rates - (2,712)
Utilisation of losses 7,021 -
Other movements -- (1,045)
Losses not recognised (3,406) (1,662)
Impact of Energy Profits Levy in the UK (71,573) -
Solidarity Contribution Tax charge (note 6.3) (46,935) -
Other changes to tax rates 339 -
Tax (charge)/credit (228,164) 33,749
Effective tax rate 89.8% 45.7%
The applicable domestic tax rates for the year ended 31 December 2022 are 50%
for entities within the Netherlands, 65% for ring-fence entities within the UK
and 19% for non-ring-fence entities within the UK. In the prior year a rate of
50% was used, being the combined rate of tax applicable oil and gas activities
in the Netherlands as the impact of tax on head office activities incurred
within the UK was not material.
6.2 Deferred tax
€'000 31 December 2022 31 December 2021
Deferred tax liability at beginning of period 57,288 --
Recognised on acquisition (note 2.10) 36,781 117,000
Profit and loss account 25,594 (59,712)
Foreign exchange differences (1,338) -
Deferred tax liability at end of period 118,325 57,288
The fair value of the deferred tax liability in the GLA acquisition acquired
amounted to €36.8 million. The deferred tax liability was calculated based
on a 40% tax rate which was the substantively enacted rate prevailing at the
date of acquisition. In the prior period, the fair value of the deferred tax
liability in the Tulip Oil acquisition was recognised based on a tax rate of
50%.
€'000 Temporary differences
Tax losses Provisions Other Total
At 14 October 2020 - - - -
Recognised on acquisition (note 2.10.1) 14,802 2,765 1,910 19,477
Deferred tax on hedge reserve in OCI (note 5.4) 5,891 5,891
- -
Profit and loss account (7,787) 1,403 (5,488) (11,872)
Deferred tax asset at 31 December 2021 7,015 4,168 2,313 13,496
Deferred tax on hedge reserve in OCI (note 5.4) - - (5,891) (5,891)
Profit and loss account (7,015) (697) 673 (7,039)
Deferred tax asset at 31 December 2022 - 3,471 (2,905) 566
The tax losses are made up of Corporate Income Tax (CIT) and State Profit
Share (SPS) losses in the Netherlands. The 'Provisions' category relates to
temporary differences on abandonment provisions. The 'Other' category relates
to temporary differences on property, plant and equipment, abandonment fixed
assets and other provisions/liabilities.
CIT losses can be carried forward indefinitely. Some losses in Kistos NL1
cannot be utilised and hence have not been recognised. This amounts to €1.0
million (2021: €1.9 million).
Tax losses of €5.4 million arising in Kistos Holdings plc have not been
recognised due to the uncertainty of future profits and where they may arise
from.
6.2.1 Changes to tax rates
In November 2022, the UK Government announced changes to the Energy Profits
Levy (EPL), increasing the rate from 25% to 35%, applied to those entities
within the ring-fence effective from 1 January 2023, and extending the period
applicable to 31 March 2028, with no provision for earlier withdrawal of the
levy. The new law became substantively enacted on 30 November 2022. The tax
rate applicable to UK entities outside of the ring-fence will increase from
19% to 25% with effect from 1 April 2023. Where applicable, UK deferred tax
balances at the balance sheet date have been remeasured using these tax rates.
6.3 Uncertain tax positions
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 €46.9 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.
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
Short-term employee benefits 2,607 935
Post-employment benefits 191 30
Total Directors' remuneration 2,798 965
Fees payable to management companies for director services 39 42
Total key management personnel compensation 2,837 1,007
No long-term benefits, termination benefits or share-based payment expense was
recognised in respect of the Directors. Further information for Directors'
remuneration is provided in the Remuneration Report within the Annual Report
and Account for 2022 (figures in which are presented in GBP). The highest-paid
Director had total remuneration for the period of €938 thousand (2021:
€490 thousand).
7.1.2 Loans to key management personnel
€'000 Year ended 31 December 2022 14 October 2020 to 31 December 2021
At start of the period 238 -
Loans made - 238
Foreign exchange movements (12) -
At end of the period 226 238
Loans to key management personnel are unsecured and interest free. No expense
was recognised in the current or prior period for bad and doubtful debts in
respect of loans made to related parties.
7.1.3 Other related party transactions
During the period the Group paid €56 thousand of rental and other
property-related costs (2021: €28 thousand) in respect of premises owned by
a member of key management personnel. No amounts were outstanding at the
period end.
7.2 Contingencies
As part of the acquisition of Tulip Oil (note 2.10) the following contingent
payments could be made to the vendor should certain events and milestones take
place:
· up to a maximum of €75 million relating to Vlieland Oil (now
Orion), triggered at FID and payable upon first hydrocarbons based on the net
reserves at time of sanction;
· up to a maximum of €75 million relating to M10a and M11,
triggered at FID and payable upon first gas, based on US$3/boe of sanctioned
reserves; and
· €10 million payable should Kistos take FID on the Q10-Gamma
prospect by 2025.
Based on management's current assessments and current status of the projects
and developments above, the contingent considerations above remain
unrecognised on the balance sheet. All contingent payments relating to the GLA
acquisition have been recognised on the balance sheet.
Contingencies arising from uncertain tax positions are disclosed in note 6.3.
7.3 Reconciliation of liabilities arising from financing activities
€'000 €90 million bond €60 million bond Bond interest payable Amortised bond costs Other non-current liabilities Lease liabilities
Opening balance
- - - - - -
Liabilities acquired (note 2.10) 86,497 - (1,080) 110 75
584
Financing cash flows 3,000 60,000 (2,933) (79) -
(7,461)
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 (2,968) 31 91
1,854
Financing cash flows (71,773) - (31) (178)
- (11,566)
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 (1,906) - 1,210
831
7.4 Auditor's remuneration
During the year, the company and its subsidiaries obtained the following
services from its auditors and affiliates:
€'000 Year ended 31 December 2022 Year ended 31 December 2021
Audit fees
Audit of the consolidated and company financial statements 154 176
Audit of the financial statements of the subsidiaries 340 227
Total audit fees 494 403
Non-audit fees
Due diligence services - 240
Other assurance services 20 -
Tax services - 12
Total non-audit fees 20 252
Total 514 655
7.5 Subsequent events
There are no adjusting events subsequent to the balance sheet date.
Significant non-adjusting events are outlined below.
7.5.1 Completion of Q10-A work programme
In March 2023, the Valaris 123 rig demobilised from the Q10-A field having
undertaken a work programme of side-tracks and well stimulations. The results
of the campaign were mixed due to mechanical issues arising from utilising the
existing well stock rather than reservoir performance issues. The results of
this campaign are still being analysed by the Group and, once fully evaluated,
will inform the decision on the timing and nature of future capital
expenditure on the field.
7.5.2 Benriach well
On 21 March 2023, the Transocean Barents rig spudded the Benriach exploration
well, in which the Group has a 25% interest.
7.5.3 Acquisition of Mime Petroleum
On 18 April 2023, the Group conditionally agreed to acquire 100% of the issued
and to be issued share capital of Mime Petroleum A.S. (Mime) from Mime
Petroleum S.a.r.l. Mime is a company focussed on exploration, development and
production projects on the Norwegian Continental Shelf, and holds a
non-operated 10% interest in the Balder joint venture (comprising the Balder
and Ringhorne fields, including the Balder X project) and a 7.4% stake in the
Ringhorne East unit, all operated by Vår Energi A.S.A. Mime's share of
hydrocarbon production from Balder and Ringhorne is expected to be
approximately 2,000 boe/d in 2023. The Balder X project comprises the Balder
Future and Ringhorne Phase IV drilling projects and is designed to extend the
life of the Balder Hub. It includes upgrading the Jotun FPSO, which is
forecast by the operator to sail away in the first half of 2024 and achieve
first oil later that year.
The consideration for the transaction is $1 plus the issue of up to 6 million
warrants exercisable into new ordinary shares of Kistos Holdings plc at a
price of 385p each. 3.6 million of the warrants can be exercised between
completion of the transaction and 18 April 2028. The balance of warrants are
exercisable from 1 June 2025 until 18 April 2028.
Upon completion, Mime's debt will comprise:
· $120 million of Super Senior bonds, attracting interest of 9.75%
per annum, 4.50% of which is payable in cash and 5.25% of which is
payable-in-kind in the form of additional Super Senior bonds. The maturity
date of the Super Senior bonds is 17 September 2026.
· $105 million of "MIME02" bonds, which will attract an interest
rate of 10.25% payable-in-kind. The maturity date of the MIME02 bonds is 10
November 2027.
A contingent payment of $45 million will be made to MIME02 bondholders in the
event 500,000 bbl (gross) have been offloaded and sold from the Jotun FPSO by
31 December 2024. This will decline to $30 million from 1 January 2025 to 28th
February 2025, to $15 million from 1 March 2025 to 31 May 2025, and to zero
thereafter. If 500,000 bbl (gross) has not been offloaded and sold from the
Jotun FPSO by 31 May 2025, the holders of Mime's Nordic Bonds will be
allocated up to 2.4 million warrants exercisable into Kistos ordinary shares
at a price of 385p each. The warrants can be exercised between 30 June 2025
and 18 April 2028. Simultaneously, up to 1.9 million of the 5.5 million
warrants issued as consideration for the Mime shares will be cancelled.
The acquisition completed on 22 May 2023.
Section 8 Significant accounting policies
The Group has consistently applied the following significant accounting
policies to all periods presented in these financial statements.
A Basis of
consolidation
b Foreign
currencies
c Revenue and other
income
d Joint
arrangements
e Finance income and finance
costs
f
Taxation
g
Leases
h
Inventory
i Intangible assets and
goodwill
j Exploration, evaluation and production
assets
k Commercial
reserves
l Depreciation based on
depletion
m
Provisions
n Property, plant and
equipment
o Employee
benefits
p Cash and cash
equivalents
q Effective interest
method
r Bond
modification
s Financial
Instruments
t
Impairment
u Fair value
a) Basis of consolidation
(i) Business combinations
The Group accounts for business combinations using the acquisition method when
the acquired set of activities and assets meets the definition of a business
and control is transferred to the Group. In determining whether a particular
set of activities and assets is a business, the Group assesses whether the set
of assets and activities acquired includes, at a minimum, an input and
substantive process, and whether the acquired set has the ability to produce
outputs.
The consideration transferred in the acquisition is generally measured at fair
value, as are the identifiable net assets acquired. Any goodwill that arises
is tested annually for impairment. Any gain on a bargain purchase is
recognised in profit or loss immediately. Transaction costs are expensed as
incurred, except if related to the issue of debt or equity securities.
Any contingent consideration is measured at fair value at the date of
acquisition, and discounted to present value if the consideration is expected
to be settled more than 12 months from the balance sheet date. If an
obligation to pay contingent consideration that meets the definition of a
financial instrument is classified as equity, then it is not remeasured, and
settlement is accounted for within equity. Otherwise, other contingent
consideration is remeasured at fair value at each reporting date and
subsequent changes in the fair value of the contingent consideration are
recognised in profit or loss.
(ii) Subsidiaries
Subsidiaries are entities controlled by the Group. The Group controls an
entity when it is exposed to, or has rights to, variable returns from its
involvement with the entity and has the ability to affect those returns
through its power over the entity. The financial statements of subsidiaries
are included in the consolidated financial statements from the date on which
control commences until the date on which control ceases.
(iii) Transactions eliminated on consolidation
Intra-group balances and transactions, and any unrealised income and expenses
(except for foreign currency transaction gains or losses) arising from
intra-group transactions, are eliminated.
(iv) Capital reorganisations
Where a capital reorganisation takes place resulting in a newly incorporated
entity acquiring the existing Group, the new entity does not meet the
definition of a business and the transaction is therefore outside the scope of
IFRS 3. In such a transaction, the substance of the Group has not changed
therefore the consolidated financial statements of the new entity are
presented using the balances and values from the consolidated financial
statements from the previous entity. The net assets of the new group remain
the same as the existing group.
b) Foreign currencies
Transactions in foreign currencies are translated into the respective
functional currencies of Group companies at the exchange rates on the date of
the transaction.
Monetary assets and liabilities denominated in foreign currencies are
translated into the functional currency at the exchange rate on the reporting
date. Non-monetary assets and liabilities that are measured at fair value in a
foreign currency are translated into the functional currency at the exchange
rate when the fair value was determined. Non-monetary items that are measured
based on historical cost in a foreign currency are translated at the exchange
rate on the date of the transaction. Foreign currency differences are
generally recognised in profit or loss and presented within finance costs.
c) Revenue and other income
Revenue from contracts with customers is measured based on the transaction
price specified in a contract with the customer, being based on quoted market
prices for the gas or liquids. All revenue is measured at a point in time,
being that point at which the Group meets its promise to transfer control of a
quantity of gas or liquids to a customer. For gas, control is transferred once
the hydrocarbons pass a specified delivery point in a pipeline. For liquids
sales, control is transferred in accordance with the incoterms specified in
the contract.
Interest income is accrued on a time basis, by reference to the principal
outstanding and at the effective interest rate applicable, which is the rate
that exactly discounts estimated future cash receipts through the expected
life of the financial asset to that asset's net carrying amount.
d) Joint operations
The Group is engaged in oil and gas exploration, development and production
through unincorporated joint arrangements; these are classified as joint
operations in accordance with IFRS 11. The Group accounts for its
proportionate share of the assets, liabilities, revenue and expenses of these
joint operations. In addition, where the Group acts as Operator to the joint
operation, the gross liabilities and receivables (including amounts due to or
from non-operating partners) of the joint operation are included in the
Group's balance sheet.
e) Finance income and finance costs
Borrowing costs directly attributable to the acquisition, construction or
production of qualifying assets, which are assets that necessarily take a
substantial period of time to be prepared for their intended use or sale, are
added to the cost of those assets, until such time as the assets are
substantially ready for their intended use or sale.
Finance costs of debt are allocated to periods over the term of the related
debt at a constant rate on the carrying amount. Arrangement fees and issue
costs are deducted from the debt proceeds on initial recognition of the
liability and are amortised and charged to the income statement as finance
costs over the term of the debt.
Interest income or expense is recognised using the effective interest method.
Dividend income is recognised in profit or loss on the date that the Group's
right to receive payment is established.
f) Taxation
Income tax expense represents the sum of the tax currently payable and
deferred tax. For CIT purposes, Kistos NL1 B.V. formed a fiscal unity with its
subsidiary Kistos NL2 B.V. from 1 April 2021. The companies are separately
liable for tax and therefore account for their tax charge/credit on a
standalone basis after taking into account the effects of horizontal
compensation within the fiscal union that is applicable from 1 April 2021.
Current and deferred tax are provided at amounts expected to be paid using the
tax rates and laws that have been enacted or substantively enacted by the
balance sheet date.
Where the Group takes positions in tax returns in which the applicable tax
regulation is subject to interpretation, it considers whether it is probable
that the relevant tax authority will accept that uncertain tax treatment. The
Group measures its tax liabilities based on either the most likely amount
(typically if the outcomes are binary) or the expected value (if there is a
range of possible values).
Current tax
Current tax comprises the expected tax payable or receivable on the taxable
income or loss for the year and any adjustment to tax payable or receivable in
respect of previous years. The amount of current tax payable or receivable is
the best estimate of the tax amount expected to be paid or received that
reflects uncertainty related to income taxes, if any. It is measured using tax
rates enacted or substantively enacted at the reporting date.
Current tax assets and liabilities are offset only if certain criteria are
met.
Deferred tax
Deferred tax is recognised in respect of temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes
and the amounts used for taxation purposes. Deferred tax is not recognised
for:
· temporary differences on the initial recognition of assets or
liabilities in a transaction that is not a business combination and that
affects neither accounting nor taxable profit or loss;
· temporary differences related to investments in subsidiaries,
associates and joint arrangements to the extent that the Group is able to
control the timing of the reversal of the temporary differences and it is
probable that they will not reverse in the foreseeable future; and
· taxable temporary differences arising on the initial recognition
of goodwill.
Deferred tax assets are recognised for unused tax losses, unused tax credits
and deductible temporary differences to the extent that it is probable that
future taxable profits will be available against which they can be used.
Future taxable profits are determined based on the reversal of relevant
taxable temporary differences. If the amount of taxable temporary differences
is insufficient to recognise a deferred tax asset in full, then future taxable
profits, adjusted for reversals of existing temporary differences, are
considered, based on business plans for individual subsidiaries in the Group.
Deferred tax assets are reviewed at each reporting date and are reduced to the
extent that it is no longer probable that the related tax benefit will be
realised; such reductions are reversed when the probability of future taxable
profits improves.
Unrecognised deferred tax assets are reassessed at each reporting date and
recognised to the extent that it has become probable that future taxable
profits will be available against which they can be used.
Deferred tax is measured at the tax rates that are expected to be applied to
temporary differences when they reverse, using tax rates enacted or
substantively enacted at the reporting date.
The measurement of deferred tax reflects the tax consequences that would
follow from the manner in which the Group expects, at the reporting date, to
recover or settle the carrying amount of its assets and liabilities.
Deferred tax assets and liabilities are offset only if certain criteria are
met.
g) Leases
At inception of a contract, the Group assesses whether a contract is, or
contains, a lease. A contract is, or contains, a lease if the contract conveys
the right to control the use of an identified asset for a period of time in
exchange for consideration.
At commencement or on modification of a contract that contains a lease
component, the Group allocates the consideration in the contract to each lease
component on the basis of its relative stand-alone price. However, for the
leases of property the Group has elected not to separate non-lease components
and accounts for the lease and non-lease components as a single lease
component.
The Group recognises a right-of-use asset and a lease liability at the lease
commencement date. The right-of-use asset is initially measured at cost, which
comprises the initial amount of the lease liability adjusted for any lease
payments made at or before the commencement date, plus any initial direct
costs incurred and an estimate of costs to dismantle and remove the underlying
asset or to restore the underlying asset or the site on which it is located,
less any lease incentives received.
The right-of-use asset is subsequently depreciated using the straight-line
method from the commencement date to the end of the lease term. In addition,
the right-of-use asset is periodically reduced by impairment losses, if any,
and adjusted for certain remeasurements of the lease liability.
The lease liability is initially measured at the present value of the lease
payments that are not paid at the commencement date, discounted using the
interest rate implicit in the lease or, if that rate cannot be readily
determined, the Group's incremental borrowing rate. Generally, the Group uses
its incremental borrowing rate as the discount rate.
The Group presents right-of-use assets within 'Property, plant and equipment'
and lease liabilities in 'Other liabilities' on the balance sheet.
The Group does not recognise right-of-use assets and lease liabilities for
leases of low-value assets and short-term leases (where the lease period is
less than one year), including IT equipment and drilling rigs. The Group
recognises the lease payments associated with these leases as an expense on a
straight-line basis over the lease term, or, in the case of short-term leases
of drilling rigs, capitalises the costs into intangible exploration and
evaluation assets, or property plant and equipment, depending on the nature of
the drilling activity.
h) Inventory
Liquids inventory (comprising crude oil and natural gas liquids) is held at
the lower of cost and net realisable value. The cost of liquids inventory is
the cost of production, including direct labour and materials, depreciation
and a portion of operating costs and other overheads allocated based on the
ratio of liquids to gas production, determined on a weighted average cost
basis. Net realisable value of liquids inventory is based on the market price
of equivalent liquids at the balance sheet date, adjusted if the sale of
inventories after that date gives additional evidence about its net realisable
value. The cost of liquids inventory is expensed in the period in which the
related revenue is recognised.
For spares and supplies inventories cost is determined on a specific
identification basis, including the cost of direct materials and (where
applicable) direct labour and a proportion of overhead expenses. Items are
classified as spares and supplies inventory where they are either standard
parts, easily resalable or available for use on non-specific campaigns, and
within property, plant and equipment or intangible exploration and evaluation
assets where they are specialised parts intended for specific projects. Write
downs to estimated net realisable value are made for slow moving, damaged or
obsolete items.
i) Intangible assets and goodwill
Recognition and measurement
Goodwill
Goodwill arising on the acquisition of subsidiaries and/or in a business
combination is measured at cost less accumulated impairment losses.
The Group allocates goodwill to CGUs or groups of CGUs that represent the
assets acquired as part of the business combination. Goodwill is tested for
impairment annually (usually at 31 December) and additionally when
circumstances indicate that the carrying value may be impaired.
Impairment is determined for goodwill by assessing the recoverable amount,
using the value in use method, of each CGU (or group of CGUs) to which
goodwill relates. When the recoverable amount of the CGU is less than its
carrying amount, an impairment loss is recognised. Impairment losses relating
to goodwill cannot be reversed in future periods.
j) Exploration, evaluation and production assets
The Group adopts the successful efforts method of accounting for exploration
and evaluation costs. Costs incurred before a licence is awarded or obtained
are expensed in the period. All licence acquisition, exploration and
evaluation costs and directly attributable administration costs are initially
capitalised by well, field or exploration area, as appropriate. Interest
payable is capitalised insofar as it relates to specific project financing.
These costs are written off as exploration costs in the income statement
unless commercial reserves have been established or the determination process
has not been completed and there are no indications of impairment.
All field development costs are capitalised as property, plant and equipment.
Property, plant and equipment related to production activities are depreciated
in accordance with the Group's depreciation accounting policy.
Where the Company drills a sidetrack from an original well, the costs of the
original well are estimated and written off, if the well is not hydrocarbon
producing.
k) Commercial reserves
P1 developed producing and P2 reserves are estimates of the amount of oil and
gas that can be economically extracted from the Group's oil and gas assets.
The Group estimates its reserves using standard recognised evaluation
techniques. The estimate is reviewed at least annually by management and as
required by independent consultants and competent professionals.
l) Depreciation based on unit-of-production
All expenditure carried within each field is depreciated from the commencement
of production on a unit of production basis, which is the ratio of oil and gas
production in the period to the estimated quantities of commercial reserves at
the end of the period plus the production in the period, generally on a
field-by-field basis or by a group of fields which are reliant on common
infrastructure. Costs used in the unit-of-production calculation comprise the
net book value of capitalised costs incurred to date. Changes in the estimates
of commercial reserves are dealt with prospectively, applied from the point in
time at which management confirm the re-assessment of the appropriate reserves
base.
Where there has been a change in economic conditions that indicates a possible
impairment in a discovery field, the recoverability of the net book value
relating to that field is assessed by comparison with the estimated discounted
future cash flows based on management's expectations of future oil and gas
prices and future costs.
In order to discount the future cash flows the Group calculates CGU-specific
discount rates. The discount rates are based on an assessment of the Group's
post-tax weighted average cost of capital (WACC).
Where there is evidence of economic interdependency between fields, such as
common infrastructure, the fields are grouped as a single CGU for
impairment-testing purposes.
Where conditions giving rise to impairment subsequently reverse, the effect of
the impairment charge is also reversed as a credit to the income statement,
net of any amortisation that would have been charged since the impairment.
m) Provisions
Provisions are determined by discounting the expected future cash flows at a
pre-tax rate that reflects current market assessments of the time value of
money and the risks specific to the liability. The unwinding of the discount
is recognised as finance cost.
Abandonment provision
An abandonment provision for decommissioning is recognised in full when the
related facilities or wells are installed. A corresponding amount equivalent
to the provision is also recognised as part of the cost of the related
property, plant and equipment. The amount recognised is the estimated cost of
abandonment, discounted to its net present value, and is reassessed each year
in accordance with local conditions and requirements. Abandonment costs
expected to be incurred within 12 months of the balance sheet date (and thus
classified as current liabilities) are not discounted.
Changes in the estimated timing of abandonment or abandonment cost estimates
are dealt with prospectively by recording an adjustment to the provision, and
a corresponding adjustment to property, plant and equipment. Where the related
item of property, plant and equipment has been fully impaired, the
corresponding adjustment is recognised in profit and loss. The unwinding of
the discount on the abandonment provision is included as a finance cost.
n) Property, plant and equipment
Recognition and measurement
Items of property, plant and equipment are measured at cost, which includes
capitalised borrowing costs less accumulated depreciation and any accumulated
impairment losses.
If significant parts of an item of property, plant and equipment have
different useful lives, then they are accounted for as separable items (major
components) of property, plant and equipment.
Any gain or loss on disposal of an item of property, plant and equipment is
recognised in the profit and loss account.
Subsequent expenditure
Subsequent expenditure is capitalised only when it is probable that the future
economic benefits associated with the expenditure will flow to the Group.
Depreciation
Depreciation is calculated to write-off the cost of items of property, plant
and equipment less their estimated residual values using the aforementioned
depreciation based on depletion accounting policy for most assets relating to
oil and gas fields and straight-line method over the estimated useful lives
for all other property, plant and equipment (including the Group's share in
the Shetland Gas Plant, which is depreciated on a straight line basis to the
estimated cessation of production date of the related gas fields).
The estimated useful lives of property, plant and equipment not relating to
oil and gas fields depreciated using the straight-line method are from three
to five years. Depreciation methods, useful lives and residual values are
reviewed at each reporting date and adjusted if appropriate.
o) Employee benefits including employee share-based payments
Short-term employee benefits are expensed as the related service is provided.
A liability is recognised for the amount expected to be paid if the Group has
a present legal or constructive obligation to pay this amount as a result of
the past service provided by the employee and the obligation can be estimated
reliably.
The grant-date fair value of equity-settled share-based payment arrangements
granted to employees is generally recognised as an expense, with a
corresponding increase in equity, over the vesting period of the awards. The
amount recognised as an expense is adjusted to reflect the number of awards
for which the related service and non-market performance conditions are
expected to be met, such that the amount ultimately recognised is based on the
number of awards that meet the related service and non-market performance
conditions at the vesting date. For share-based payment awards with
non-vesting conditions, the grant-date fair value of the share-based payment
is measured to reflect such conditions and there is no true-up for differences
between expected and actual outcomes.
p) Cash and cash equivalents
Cash and cash equivalents comprise cash at bank, demand deposits and other
short-term highly liquid investments with original maturities of three months
or less that are readily convertible to a known amount of cash and are subject
to an insignificant risk of changes in value.
q) Effective interest method
The effective interest method is a method of calculating the amortised cost of
a financial asset or liability and allocating interest income or expense over
the relevant period. The effective interest rate is the rate that exactly
discounts estimated future cash receipts (including all fees on points paid or
received that form an integral part of the effective interest rate,
transaction costs and other premiums or discounts) through the expected life
of the financial asset, or, where appropriate, a shorter period.
Income is recognised on an effective interest basis for debt instruments other
than those financial assets classified as at FVTPL.
r) Bond modification
When the Group, with an existing lender, exchanges one debt instrument for
another with substantially different terms, such an exchange is accounted for
as an extinguishment of the original financial liability and the recognition
of a new financial liability. Similarly, the Group accounts for substantial
modification of the terms of an existing liability or part of it as an
extinguishment of the original financial liability and the recognition of a
new liability. The terms are substantially different if the discounted present
fair value of the cash flows under the new terms, including any transaction
costs paid and discounted using the original effective interest rate is at
least 10% different from the discounted present value of the remaining cash
flows of the original financial liability. If the modification is not
substantial, the difference between: (i) the carrying amount of the liability
including transaction costs before the modification and (ii) the present value
of the cash flows after modification is recognised through the profit and loss
account as a modification gain or loss.
Where debt instruments issued by the Group are repurchased, the financial
liability is derecognised at the point at which cash consideration is settled.
Upon derecognition, the difference between the liability's carrying amount
that has been cancelled and the consideration paid is recognised as a gain or
loss in the income statement.
s) Financial instruments
Recognition and initial measurement
Financial instruments are recognised as a financial asset or financial
liability when the Group becomes a party to the contractual provisions of the
instrument.
A financial asset (unless it is a trade receivable without a significant
financing component) or financial liability is initially measured at fair
value plus, for an item not at FVTPL, transaction costs that are directly
attributable to its acquisition or issue. Financial assets and liabilities are
discounted to present value (with the unwinding of discount recognised in
finance costs), unless the impact is not material and/or the expected
settlement of the instrument is within 12 months of the balance sheet date. A
trade receivable without a significant financing component is initially
measured at the transaction price.
Classification and subsequent measurement
Financial assets
On initial recognition, a financial asset is classified as measured at:
amortised cost; fair value through other comprehensive income (FVOCI) - debt
investment; FVOCI - equity investment; or FVTPL.
When measuring the fair value of an asset or a liability, the Company uses
observable market data as far as possible. Fair values are categorised into
different levels in a fair value hierarchy based on the inputs used in the
valuation techniques as follows:
· Level 1: Quoted prices (unadjusted) in active markets for
identical assets or liabilities.
· Level 2: Inputs other than quoted prices included in Level 1 that
are observable for the asset or liability, either directly (i.e., as prices)
or indirectly (i.e., derived from prices).
· Level 3: Inputs for the asset or liability that are not based on
observable market data (unobservable inputs).
If the inputs used to measure the fair value of an asset or a liability fall
into different levels of the fair value hierarchy, then the fair value
measurement is categorised in its entirety in the same level as the lowest
level input that is significant to the entire measurement.
Financial assets are not reclassified subsequent to their initial recognition
unless the Group changes its business model for managing financial assets, in
which case all affected financial assets are reclassified on the first day of
the first reporting period following the change in the business model.
A financial asset is measured at amortised cost if it meets both of the
following conditions and is not designated as at FVTPL:
· it is held within a business model whose objective is to hold
assets to collect contractual cash flows; and
· its contractual terms give rise on specified dates to cash flows
that are solely payments of principal and interest on the principal amount
outstanding.
All financial assets not classified as measured at amortised cost or FVOCI as
described above are measured at FVTPL. This includes all derivative financial
assets. On initial recognition, the Group may irrevocably designate a
financial asset that otherwise meets the requirements to be measured at
amortised cost or at FVOCI as at FVTPL if doing so eliminates or significantly
reduces an accounting mismatch that would otherwise arise.
Financial assets - subsequent measurement and gains and losses
· Financial assets at FVTPL - These assets are subsequently
measured at fair value. Net gains and losses, including any interest or
dividend income, are recognised in profit or loss.
· Financial assets at amortised cost - These assets are
subsequently measured at amortised cost using the effective interest method.
The amortised cost is reduced by impairment losses. Interest income, foreign
exchange gains and losses and impairment are recognised in profit or loss. Any
gain or loss on derecognition is recognised in profit or loss.
Financial liabilities - classification, subsequent measurement and gains and
losses
Financial liabilities are classified as measured at amortised cost or FVTPL. A
financial liability is classified as at FVTPL if it is classified as
held-for-trading, it is a derivative or it is designated as such on initial
recognition. Financial liabilities at FVTPL are measured at fair value and net
gains and losses, including any interest expense, are recognised in profit or
loss. Other financial liabilities are subsequently measured at amortised cost
using the effective interest method. Interest expense and foreign exchange
gains and losses are recognised in profit or loss. Any gain or loss on
derecognition is also recognised in profit or loss.
Derecognition
Financial assets
The Group derecognises a financial asset when:
· the contractual rights to the cash flows from the financial asset
expire; or
· it transfers the rights to receive the contractual cash flows in
a transaction in which either:
o substantially all of the risks and rewards of ownership of the financial
asset are transferred; or
o the Group neither transfers nor retains substantially all of the risks and
rewards of ownership and it does not retain control of the financial asset.
The Group enters into transactions whereby it transfers assets recognised in
its balance sheet but retains either all or substantially all of the risks and
rewards of the transferred assets. In these cases, the transferred assets are
not derecognised.
Financial liabilities
The Group derecognises a financial liability when its contractual obligations
are discharged or cancelled or expire. The Group also derecognises a financial
liability when its terms are modified and the cash flows of the modified
liability are substantially different, in which case a new financial liability
based on the modified terms is recognised at fair value, and if the Group
repurchases a debt instrument it previously issued.
On derecognition of a financial liability, the difference between the carrying
amount extinguished and the consideration paid (including any non-cash assets
transferred or liabilities assumed) is recognised in the profit and loss
account. If only part of a financial liability is derecognised, the previous
carrying amount of the financial liability is allocated between the part that
continues to be recognised and the part that is derecognised based on the
relative fair values of those parts on the date of the repurchase, with the
difference between the carrying amount allocated to the part derecognised and
the consideration paid recognised within finance costs.
Share capital - ordinary shares
Incremental costs directly attributable to the issue of ordinary shares, net
of any tax effects, are recognised as a deduction from equity. Income tax
relating to transaction costs of an equity transaction is accounted for in
accordance with IAS12.
Derivative financial instruments and hedge accounting
From time to time, the Group holds derivative financial instruments to hedge
cash flow risk exposures. Embedded derivatives are separated from the host
contract and accounted for separately if the host contract is not a financial
asset and certain criteria are met.
Derivatives are initially measured at fair value. Subsequent to initial
recognition, derivatives are measured at fair value, and changes therein are
generally recognised in profit or loss.
The Group designates (i) certain derivatives as hedging instruments to hedge
the variability in cash flows associated with highly probable forecast
transactions arising from changes in commodity prices and (ii) certain
derivatives and non-derivative financial liabilities as hedges of currency
risk on a net investment in a foreign operation.
At inception of designated hedging relationships, the Group documents the risk
management objective and strategy for undertaking the hedge. The Group also
documents the economic relationship between the hedged item and the hedging
instrument, including whether the changes in cash flows of the hedged item and
hedging instrument are expected to offset each other.
Cash flow hedge
When a derivative is designated as a cash flow hedging instrument, the
effective portion of changes in the fair value of the derivative is recognised
in OCI and accumulated in the hedging reserve. The effective portion of
changes in the fair value of the derivative that is recognised in OCI is
limited to the cumulative change in fair value of the hedged item, determined
on a present value basis, from inception of the hedge. Any ineffective portion
of changes in the fair value of the derivative is recognised immediately in
profit or loss.
The Group designates only the change in fair value of the spot element of
forward exchange contracts as the hedging instrument in cash flow hedging
relationships. The change in fair value of the forward element of forward
exchange contracts (forward points) is separately accounted for as a cost of
hedging and recognised in a costs of hedging reserve within equity.
For all other hedged forecast transactions, the amount accumulated in the
hedging reserve and the cost of hedging reserve is reclassified to profit or
loss in the same period or periods during which the hedged expected future
cash flows affect profit or loss.
If the hedge no longer meets the criteria for hedge accounting or the hedging
instrument is sold, expires, is terminated or is exercised, then hedge
accounting is discontinued prospectively. When hedge accounting for cash flow
hedges is discontinued, the amount that has been accumulated in the hedging
reserve remains in equity until, for a hedge of a transaction resulting in the
recognition of a non-financial item, it is included in the non-financial
item's cost on its initial recognition or, for other cash flow hedges, it is
reclassified to profit or loss in the same period or periods as the hedged
expected future cash flows affect profit or loss.
If the hedged future cash flows are no longer expected to occur, then the
amounts that have been accumulated in the hedging reserve and the cost of
hedging reserve are immediately reclassified to profit or loss.
t) Impairment
Non-derivative financial assets
The Group recognises loss allowances for expected credit losses (ECLs) on
financial assets measured at amortised cost.
The Group measures loss allowances at an amount equal to lifetime ECLs, except
for the following, which are measured at 12-month ECLs:
· debt securities that are determined to have low credit risk at
the reporting date; and
· other debt securities and bank balances for which credit risk
(i.e., the risk of default occurring over the expected life of the financial
instrument) has not increased significantly since initial recognition.
Loss allowances for trade receivables and contract assets are always measured
at an amount equal to lifetime ECLs.
When determining whether the credit risk of a financial asset has increased
significantly since initial recognition and when estimating ECLs, the Group
considers reasonable and supportable information that is relevant and
available without undue cost or effort. This includes both quantitative and
qualitative information and analysis, based on the Group's historical
experience and informed credit assessment and including forward-looking
information.
The Group assumes that the credit risk on a financial asset has increased
significantly if it is more than 30 days past due.
The Group considers a financial asset to be in default when:
· the borrower is unlikely to pay its credit obligations to the
Group in full, without recourse by the Group to actions such as realising
security (if any is held); or
· the financial asset is more than 90 days past due.
The Group considers a debt security to have low credit risk when its credit
risk rating is equivalent to the globally understood definition of investment
grade.
Lifetime ECLs are the ECLs that result from all possible default events over
the expected life of a financial instrument. Twelve-month ECLs are the portion
of ECLs that result from default events that are possible within the 12 months
after the reporting date (or a shorter period if the expected life of the
instrument is less than 12 months).
The maximum period considered when estimating ECLs is the maximum contractual
period over which the Group is exposed to credit risk.
Measurement of ECLs
ECLs are a probability-weighted estimate of credit losses. Credit losses are
measured as the present value of all cash shortfalls (i.e., the difference
between the cash flows due to the entity in accordance with the contract and
the cash flows that the Group expects to receive). ECLs are discounted at the
effective interest rate of the financial asset.
Credit-impaired financial assets
At each reporting date, the Group assesses whether financial assets carried at
amortised cost and debt securities at FVOCI are credit-impaired. A financial
asset is credit-impaired when one or more events that have a detrimental
impact on the estimated future cash flows of the financial asset have
occurred.
Evidence that a financial asset is credit-impaired includes the following
observable data:
· significant financial difficulty of the borrower or issuer;
· a breach of contract such as a default or being more than 90 days
past due;
· the restructuring of a loan or advance by the Group on terms that
the Group would not consider otherwise;
· it is probable that the borrower will enter bankruptcy or another
financial reorganisation; or
· the disappearance of an active market for a security because of
financial difficulties.
Loss allowances for financial assets measured at amortised cost are deducted
from the gross carrying amount of the assets.
For debt securities at FVOCI, the loss allowance is charged to profit or loss
and is recognised in OCI.
Write-off
The gross carrying amount of a financial asset is written off when the Group
has no reasonable expectations of recovering a financial asset in its entirety
or a portion thereof. For individual customers, the Group has a policy of
writing off the gross carrying amount when the financial asset is 180 days
past due based on historical experience of recoveries of similar assets. For
corporate customers, the Group individually makes an assessment with respect
to the timing and amount of write-off based on whether there is a reasonable
expectation of recovery. The Group expects no significant recovery from the
amount written off. However, financial assets that are written off could still
be subject to enforcement activities in order to comply with the Group's
procedures for recovery of amounts due.
Non-financial assets
At each reporting date, the Group reviews the carrying amounts of its
non-financial assets to determine whether there is any indication of
impairment. If any such indication exists, then the asset's recoverable amount
is estimated. Goodwill is tested annually for impairment.
For impairment testing, assets are grouped together into the smallest group of
assets that generate cash inflows from continuing use that are largely
independent of the cash inflows of other assets or CGUs. Goodwill arising from
a business combination is allocated to CGUs or groups of CGUs that are
expected to benefit from the synergies of the combination.
The recoverable amount of an asset or CGU is the greater of its value in use
and its fair value less costs to sell. Value in use is based on the estimated
future cash flows, discounted to their present value using a pre-tax discount
rate that reflects current market assessments of the time value of money and
the risks specific to the asset or CGU.
An impairment loss is recognised if the carrying amount of an asset or CGU
exceeds its recoverable amount.
Impairment losses are recognised in profit or loss. They are allocated first
to reduce the carrying amount of any goodwill allocated to the CGU, and then
to reduce the carrying amounts of the other assets in the CGU on a pro rata
basis.
An impairment loss in respect of goodwill is not reversed. For other assets,
an impairment loss is reversed only to the extent that the asset's carrying
amount does not exceed the carrying amount that would have been determined,
net of depreciation or amortisation, if no impairment loss had been
recognised.
u) Fair value
Fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date in the principal or, in its absence, the most
advantageous market to which the Group has access at that date. The fair value
of a liability reflects its non-performance risk.
A number of the Group's accounting policies and disclosures require the
measurement of fair values, for both financial and non-financial assets and
liabilities.
When one is available, the Group measures the fair value of an instrument
using the quoted price in an active market for that instrument. A market is
regarded as active if transactions for the asset or liability take place with
sufficient frequency and volume to provide pricing information on an ongoing
basis.
If there is no quoted price in an active market, then the Group uses valuation
techniques that maximise the use of relevant observable inputs and minimise
the use of unobservable inputs. The chosen valuation technique incorporates
all of the factors that market participants would take into account in pricing
a transaction.
If an asset or a liability measured at fair value has a bid price and an ask
price, then the Group measures assets and long positions at a bid price and
liabilities and short positions at an ask price.
The best evidence of the fair value of a financial instrument on initial
recognition is normally the transaction price - i.e., the fair value of the
consideration given or received. If the Group determines that the fair value
on initial recognition differs from the transaction price and the fair value
is neither evidenced by a quoted price in an active market for an identical
asset or liability nor based on a valuation technique for which any
unobservable inputs are judged to be insignificant in relation to the
measurement, then the financial instrument is initially measured at fair
value, adjusted to defer the difference between the fair value on initial
recognition and the transaction price. Subsequently, that difference is
recognised in profit or loss on an appropriate basis over the life of the
instrument but no later than when the valuation is wholly supported by
observable market data, or the transaction is closed out.
Appendix A: Glossary
2C Best estimate of contingent resources
2P Proved plus probable reserves
Adjusted EBITDA EBITDA, excluding the effects of significant one-off and/or non-cash items of
income and expenditure which may have, in the opinion of management, an impact
on the quality of earnings. Adjusted EBITDA excludes development expenses,
share-based payment expenses, transaction costs and movements in contingent
consideration payable.
AFE Authority For Expenditure
Average realised Calculated as revenue from gas production divided by units of gas sold for the
gas price period.
Units of gas sold in a period may be different to units of gas produced in a
period.
bbl Barrel of oil
boe Barrels of oil equivalent
boepd Barrels of oil equivalent produced per day
cijns A royalty tax levied on oil and gas sales in the Netherlands. Historically set
a 0% in respect of gas produced offshore; but for 2023 and 2024 temporarily
increasing to a rate of 65% on turnover in excess of €0.5 per cubic metre of
gas sold.
CIT Dutch Corporate Income Tax
Company Kistos Holdings plc
DEI Diversity, equality and inclusion
DSA Decommissioning Security Agreement
EBITDA Earnings (operating profit) before interest, tax, depreciation, impairment and
amortisation
EBN Energie Beheer Nederland
EIR Effective interest rate
EPL Energy Profits Levy
FID Final Investment Decision
FPSO Floating production storage and offloading vessel
G&A General and administrative expenditure
GLA Greater Laggan Area
GLA acquisition The acquisition by the Group of a 20% working interest in the GLA licences,
producing gas fields and associated infrastructure alongside various interests
in certain other exploration licences, including a 25% interest in the
Benriach prospect, from TotalEnergies E&P UK Limited.
Group Kistos Holdings plc including its subsidiaries
JV Joint venture
Kistos group Kistos Holdings plc including its subsidiaries
LNG Liquefied natural gas
Mime Mime Petroleum A.S.
MMBtu Million British Thermal units
MWh Megawatt hour
MWhe Megawatt hour equivalent
Net debt/net cash Cash and cash equivalents less face value of Nordic Bonds outstanding.
Management's definition of net debt is different to that defined in the
leverage ratio calculation in respect of the Group's borrowings (as calculated
in note 5.1.2).
NGL Natural gas liquids
NSTA North Sea Transition Authority
OCI Other comprehensive income
P50 estimate 50(th) percentile estimate, equivalent to 2P
SGP Shetland Gas Plant
SodM State Supervisor of Mines
Solidarity Contribution Tax A tax levied by the Dutch government, following the adoption of Council
Regulation (EU) 1854/2022, which required EU member states to introduce a
'solidarity contribution' for companies active in the oil, gas, coal and
refinery sectors. The Dutch implementation of this solidarity contribution has
been legislated by a retrospective 33% tax on 'excess profit' realised during
2022, with 'excess profit' defined as that profit exceeding 120% of the
average profit of the four previous financial years. Companies in scope are
those realising at least 75% of their turnover through the production of oil
and natural gas, mining activities, refining of petroleum or coke oven
products.
SPS Dutch State Profit Share tax
TotalEnergies TotalEnergies E&P Limited
Unit opex Calculated as cash production costs divided by production (see appendix B).
Appendix B Non-IFRS Measures
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.
€'000 Note 31 December 2022 31 December 2021
Cash and cash equivalents 4.1 211,980 77,266
Face value of bond debt 5.1 (81,572) (150,000)
Net cash/(debt) 130,408 (72,734)
Difference between carrying value and face value of bond debt 5.1 (1,134) 1,958
Lease liabilities 4.4 (1,211) (91)
Net cash/(debt) for leverage ratio 5.1.2 128,063 (70,867)
B3 Unit opex
Unit opex is defined as total production (converted to MWh equivalent using
the conversion factors in Appendix C) divided by adjusted operating costs.
Adjusted operating costs are operating costs per the income statement less
accounting movements in inventory, which are primarily those operating costs
capitalised into liquids inventory. Such costs are only recognised in the
income statement upon sale of the related product (rather than as incurred).
€'000 Year ended 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 (€/MWh) 5.8 3.7
Pro forma unit opex (€/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
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