REG - Kistos Holdings PLC - Full-year results for the year ended 31/12/23
13/05/2024 07:00
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RNS Number : 1304O Kistos Holdings PLC 13 May 2024
13(th) May 2024
Kistos Holdings plc
("Kistos", "the Company", or the "Group")
Full-year results for the year ended 31 December 2023
Kistos (LSE: KIST), the low carbon intensity energy production company
pursuing opportunities in line with the energy transition, is pleased to
provide a summary of its audited full-year results for the year ended 31
December 2023. A copy of the Company's full audited annual report and accounts
will be made available shortly on the Company's website at www.kistosplc.com.
2023 Highlights
· On a pro forma basis, Group production averaged 8.8 kboe/d (2022:
10.9 kboe/d), reflecting natural production decline from our UK and Dutch
assets, unplanned production interruptions relating to third-party
infrastructure in the Netherlands, partially offset by the inclusion of
production from the Balder and Ringhorne areas in Norway.
· Adjusted pro forma EBITDA was €122 million (2022: €517 million),
reflecting the fall in the gas price from exceptionally high levels in 2022.
· Completed the acquisition of Mime Petroleum AS ("Mime"), adding 24
mmboe of 2P reserves (as of 1 January 2023) and in excess of 2,000 boe/d of
production with material future production upside from the Balder Future
development (Kistos 10%).
· Year-end 2P reserves of 27.9 mmboe, up from 12.7 mmboe on 31 December
2022 following the completion of the Mime Acquisition.
12 months ended 31 December 2023
2023 (actual) 2023 (pro forma)(1) 2022 (actual) 2022 (pro forma)(1)
Average production rate(2) boe/d 9,200 8,800 10,600 10,900
Revenue €'000 206,997 223,092 411,512 568,445
Average realised sales price(2) €/boe 71 71 167 158
Unit opex(3) €/boe 24 25 10 12
Adjusted EBITDA(4) €'000 120,777 122,319 380,015 517,202
Statutory profit/(loss) before tax €'000 (45,858) n/a 254,125 n/a
Cash €'000 194,598 194,598 211,980 211,980
1. Pro forma figures for 2023 include Kistos Norway as if it had been
acquired on 1 January 2023. The acquisition completed on 23 May 2023. Pro
forma figures for 2022 include GLA as if it had been acquired on 1 January
2022. The acquisition completed in July 2022 and is therefore not included in
the actual results to 30 June 2022. Minor adjustments have been made to
comparative pro forma information following receipt of additional information
after completion of the GLA acquisition and to align with the Group's
accounting policies and methodology as used in the 2022 Annual Report and
Accounts.
2. Average production rate includes gas, oil and natural gas liquids,
and is rounded to the nearest 100 barrels of oil equivalent per day. The
actual average production rate reflects the number of days during the year
businesses were controlled by the Group. Sales and production volumes are
converted to estimated barrels of oil equivalent (boe) using the conversion
factors in Appendix C to the Financial Statements.
3. Non-IFRS measure. Refer to the definition within the glossary and
reconciliation in Appendix B3 to the Financial Statements.
4. Non-IFRS measure. Refer to the definition within the glossary and
reconciliation in note 2.2.2 and Appendix B1 to the Financial Statements.
Financial
Strong operating cash flow performance and balance sheet with improved
flexibility
· Statutory loss after tax of €25 million (2022: €26 million profit
after tax) including €59 million of impairment charges, primarily relating
to write-offs in the UK Exploration segment.
· Strong operating cash flow generation of €203 million (2022: €291
million) despite weaker commodity price environment
· Cash balances on 31 December 2023 of €195 million (31 December
2021: €212 million) and net debt of €24 million following the assumption
of $225 million of bonds issued by Mime, with tax repayment of €80 million
to be received in December 2024.
· Retired all the outstanding bonds (€82 million) originally issued
by Kistos NL2 as part of the acquisition of Tulip Oil, in December 2023. This
will save €15 million on future interest costs and has improved our
financial flexibility.
· Capital expenditure on a cash basis was €119 million (2022: €20
million), primarily representing the significant planned ongoing investment in
Norway to progress the Balder Future project to production.
Operational
Increasing the Group's reserve base and production profile
· Year-end 2P reserves of 27.9 mmboe, up from 12.7 mmboe on 31 December
2022 following the completion of the Mime acquisition.
· Production from newly acquired Norway assets increased 50% through
the year from 312 kboe in H1 2023 to 478 kboe in H2 2023 as new wells came
onstream at the Ringhorne platform.
· Estimated Scope 1 CO(2)e emissions from our operated activities
offshore were less than 0.01 kg/boe in 2023 (excluding necessary flaring
during drilling campaigns).
Outlook
Establishing a diversified geographic portfolio with exposure across the
energy value chain
· Completion of UK gas storage assets acquisition from EDF in April
2024, diversifying the Company's asset portfolio into a stable marketplace
that offers significant growth potential.
· On the Balder Future project in Norway, targeting c.140 mmboe gross
(c.14 mmboe net), 11 out of 14 new production wells have been completed, ready
for start-up when the Jotun FPSO is installed (scheduled by the operator to be
in Q4 2024).
· Net debt on 30 April 2024 of €148 million, following cash
consideration paid for UK gas storage assets, ongoing Balder Future Project
funding and UK tax payments made in Q1 2024.
· Tax repayment (primarily in respect of capital expenditure incurred
during 2023 on Balder Future) of €80 million (excluding accrued interest)
due to be received in December 2024.
· Continue to explore value-accretive opportunities in the traditional
energy sector, despite challenging fiscal environments, and also in the energy
transition space.
Andrew Austin, Executive Chairman of Kistos, commented:
"2023 saw significant changes to the operating environment with commodity
prices sharply down on the previous year and an increasingly restrictive
fiscal regime in the UK. However, the Group continued to maintain a strong
balance sheet, paying down historic debt and generating meaningful cash flow.
Kistos has made significant progress in diversifying its asset base to
mitigate against the barriers to further investment in the UK North Sea
imposed by the UK Government. The acquisition of UK onshore gas storage assets
is a demonstration of the Group's ability to identify opportunities outside of
its offshore production portfolio and broaden its sources of revenue.
As a management team fully aligned with shareholders, we remain focussed on
seeking value for our investments which complement our existing portfolio and
offer value-accretive upside."
Enquiries
Kistos Holdings plc via Hawthorn Advisors
Andrew Austin
Panmure Gordon (NOMAD, Joint Broker) Tel: 0207 886 2500
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. In April 2024,
Kistos completed the acquisition of UK gas storage assets, which due to the
fast cycle nature of the facility, can deliver up to 11% of the UK's flexible
daily gas capacity if called upon.
Kistos is a low carbon intensity energy producer with Estimated Scope 1 CO(2)e
emissions from our operated activities offshore Netherlands of less than 0.01
kg/boe in 2023 (excluding necessary flaring during drilling campaigns).
Executive Chairman's Statement
Continued growth
I am delighted to be able to report Kistos' results for the year ended 31
December 2023, with Adjusted EBITDA for the period €122 million on a pro
forma basis.
This result was a reduction from the 2022 pro forma Adjusted EBITDA of €517
million, primarily due to the exceptionally high gas prices seen in the prior
period. We ended 2023 with total cash of €195 million (2022: €212
million), and Kistos' strong financial position during the year was one of the
reasons we were able to acquire Mime Petroleum (subsequently renamed Kistos
Energy Norway AS) in May 2023 and assume its bond debt. This resulted in a
Group net debt position at the end of the period of €24 million, following
the redemption in December of the remaining outstanding bonds that were
originally issued on acquisition of Tulip Oil. The redemption of these bonds
has resulted in a €15 million saving on future interest costs, as well as
improving our financial flexibility by making it easier to manage cash within
the Group and permit future external distributions to shareholders.
Production from the Kistos-operated Q10-A field in the Netherlands was
impacted by downtime from the scheduled maintenance period, which began in
June, and a planned workover campaign that commenced in the fourth quarter of
2022 and concluded in the first quarter of 2023. The results of this campaign
were mixed, mainly due to mechanical issues arising from utilising the
existing well stock rather than reservoir performance issues. Nevertheless net
output from Q10-A reduced significantly from 4,700 boepd in 2022 to 2,700
boepd in 2023 and our team is now focused on minimising future production
declines to ensure we extract the maximum value from this asset.
Following its acquisition by Kistos and successful integration into the Group,
Norway production increased by more than 50% from 312 kbbl in the first half
of 2023 to 478 kbbl in the second half of 2023. This was achieved as Vår
Energi, the Balder area operator, brought new wells onstream and production
efficiency improved following a summer maintenance turn-around. The average
net daily production in Norway for the year was 2,200 boepd, but more than
3,000 boepd in the final quarter.
Meanwhile, the Balder Future development, which is expected to boost our
output from the Norwegian Continental Shelf (NCS) to a daily peak during 2025
of 10,000 boepd, continues to make progress. The upgrade of the Jotun floating
production storage and offloading vessel (FPSO) is ongoing, with Vår
reporting that work on the vessel is, as at April 2024, more than 95%
complete. It is focused on executing the remaining construction and
commissioning work to enable inshore sail away in time to allow production
start-up in the fourth quarter of the year. The project's drilling and subsea
facilities activities are progressing according to schedule.
In the Greater Laggan Area (GLA) offshore the UK, despite an unplanned
shutdown at the Shetland Gas Plant (SGP) in December, which was caused by an
incident in the heating medium system, the GLA fields and infrastructure
enjoyed good uptime and produced an average of 4,000 boepd net to Kistos, a
decrease from 5,900 boepd in 2022 but in line with the budget. Looking
forward, the GLA partners continue to pursue the potential development of the
Glendronach field and we expect to benefit from Shell's decision to develop
the Victory gas field, which will utilise GLA infrastructure and the SGP, and
is due onstream before the end of 2025.
We were disappointed when the Benriach exploration well failed to find
hydrocarbons in commercial quantities. However, we were pleased that
operations were completed safely and under budget and an extensive data
acquisition programme was conducted, which will help inform the geological
interpretation of the area. Although we benefitted from enhanced capital
allowances in relation to the this well (resulting in the post-tax cost to
Kistos being only €4 million) under the Energy Profits Levy (EPL) regime, we
continue to see this tax in particular, and fiscal uncertainty in general, as
major barriers to investment in the UK North Sea. The recent announcement by
the UK Government that EPL is to be extended for another year (to 2029) is at
odds with what was supposed to be a temporary 'windfall' tax on exceptional
profits, especially as the average 2023 UK gas price was lower than the 2021
average (which was prior to the commencement of the Russia-Ukraine conflict).
Since the end of 2023, we announced and completed the acquisition of EDF's
onshore UK gas storage business for cash consideration of £25 million (less
closing working capital adjustments). Our entry into this market is another
step in our strategy to expand the business through value-accretive
acquisitions. However, these facilities also diversify our presence across the
energy value chain, giving us a foothold in the midstream market, and align
with our objective to own assets with a role to play in the energy transition.
We welcome the gas storage team to Kistos and look forward to benefitting from
their experience at these sites as we assume operatorship. Their specialist
expertise will be highly valuable as we seek to maximise the potential of the
assets and evaluate all options to expand and extend operations via other
energy storage sources such as compressed air or hydrogen. In essence, Kistos
now owns one of the most flexible 'batteries' in the UK, which is vital for
the nation's energy security and supply.
Finally, I would like to thank our employees and contractors for their work
and commitment to the Company and to thank our suppliers, co-venturers and
others for their continued support. It enabled us to build on our platform
since the end of 2022 and we will continue to do so in the future. Although we
do not set explicit long-term targets for reserves or production, we will
maintain our focus on generating substantial returns for investors and I look
forward to reporting further progress during the remainder of 2024.
Andrew Austin
Executive Chairman
Chief Executive Officer's Review
Review of Operations
2023 saw Kistos enter Norway with the acquisition of Mime Petroleum, bringing
geographical and operational diversification, and significantly increasing the
Group's reserves and resources base.
The Netherlands
Q10-A
Q10-A (Kistos 60% and operator) production in 2023 was 2,700 kboepd compared
to 4,700 kboepd in 2022. Production was adversely impacted by downtime due to
a compressor leak on the TAQA-operated P15-D platform identified following
restart of operations after the planned summer maintenance shutdown. This
resulted in significantly reduced production rates until the issue was
rectified in early September.
Production for the year was also impacted by the mixed results of the well
intervention campaign, which concluded during Q1 2023 without achieving the
forecasted increase in production rates. We continue to review and integrate
the results of these activities into our wider subsurface understanding of the
field to evaluate any remaining opportunities, but we now anticipate the 2P
reserves recoverable from the field to be lower than originally thought.
The Group is also co-operating closely with the operator and other users of
the P15-D platform and associated infrastructure to ensure volumes are
maximised and unit operating costs are minimised in the coming years. The
objective of this collaborative exercise, which includes potential new
developments, is to extend the economic life of the hub for the benefit of all
users.
Average realised gas prices fell by 59% to €43/MWh from €105/MWh a year
earlier. Combined with a 45% decrease in production rates, this caused total
Netherlands revenue in the period to decrease by 76% to €67 million versus
€285 million in 2022.
Critically, our Scope 1 emissions intensity remained one of the lowest in the
industry, at less than 0.002 kg CO(2)e/boe (excluding flaring from drilling
operations).
Orion
The Q10-A Orion oil field (Kistos 60% and operator) is located in the Vlieland
sandstone formation, which is a stratigraphically shallower formation
deposited above the Q10-A gas field. This is a proven play in the area and,
although this reservoir has low porosity and permeability, it contains natural
fractures that can significantly enhance productivity. This was demonstrated
in the third quarter of 2021, when Kistos drilled an appraisal well and flow
tested an 825-metre horizontal section at a maximum rate of 3,200 boepd.
The Concept Select phase of the development was split into two parts, the
first of which completed during Q3 2023. The second phase is nearing
completion and, should the decision be taken to progress the project, FID
could occur in the second half of 2024, with first oil in early 2026. In the
event it goes ahead, this relatively low-cost project is expected to utilise
the existing facilities at Q10-A and P15-D. Under currently enacted fiscal
regimes, the oil produced would be among the lowest-taxed barrels in the North
Sea at a rate of approximately 50%.
M10a/M11
During the first half of 2022, Kistos applied for the M10a and M11 licences
(Kistos 60% and operator) north of the Wadden Islands to be extended beyond 30
June 2022. Initially, the extension was denied but during 2023, Kistos
successfully appealed against this decision and the licences were re-awarded
and extended to 31 August 2028. As part of the licence extension, Kistos was
required, prior to 28 February 2024, to apply for a permit to drill an
appraisal well and to commence operations no later than 31 August 2025.
Following a period of close engagement with local municipalities and other
stakeholders in the latter part of 2023, we submitted a request for an
extension to the 28 February submission deadline. An update on the status of
M10a/M11 will be provided once we receive responses from the relevant
authorities.
Other
In January 2023, Kistos was awarded three new offshore exploration licences
(P12b, Q13b and Q14), which are adjacent to the existing Q10 block and cover a
total of 507 km(2). Kistos holds a 60% operated working interest in these
licences and is partnered by EBN, which holds the remaining 40%. Initial
evaluation of the acreage has now commenced, with previously identified
prospects being ranked against our wider portfolio of exploration
opportunities.
Onshore, after concluding the safe abandonment of three wells (HRK-1, DKK-3
and DKK-4) at the end of 2022, Kistos commenced the process of land
remediation and returning sites to landowners. In 2024, Kistos will continue
the remaining abandonment work, focusing on removing the pipeline and filling
in remaining cavities.
Norway
Production and drilling activity
Net production from the Balder and Ringhorne fields (Kistos 10%) in the period
from acquisition to the end of the year averaged 2,500 boepd, with 22 wells
producing oil during the year. Under the joint lifting agreement with Vår, 10
cargoes of crude were lifted from the Balder floating production unit (FPU) in
the period post-acquisition, totalling 533 kboe net to Kistos with an average
realised price of $81/bbl. For 2024, Kistos has entered into a new sales and
lifting arrangement whereby Kistos will sell its share of crude oil only when
it has built up sufficient entitlement to fill an offload tanker but will
continue to be paid monthly on a produced quantity basis.
Production was positively impacted in the period by the restart in May of the
rich-gas riser between the Balder FPU and the Ringhorne platform. This had
been temporarily shut in during the first quarter of the year and was
permanently replaced in September 2023 during the planned Balder FPU
turnaround. Overall production efficiency for Balder and Ringhorne Øst was
87% but improved as the year progressed, reaching 98% in the final quarter.
Other activities in 2023 included: a well intervention campaign to restore
output from Ringhorne Øst; the drilling and completion of six new wells with
the West Phoenix semi-submersible drilling rig as part of the Balder Future
campaign; and the completion of the first of five planned Ringhorne Phase IV
wells to be drilled from the Ringhorne platform. The remaining Ringhorne Phase
IV wells are anticipated to be completed by early 2025.
We estimate that the full year Scope 1 and Scope 2 emissions intensity from
our Norwegian assets was 18 kg CO(2)e/boe.
Balder Future and other developments
The Balder Future project involves the drilling of 14 new production wells
plus one new water injector on the Balder field, alongside the refurbishment
of the Jotun FPSO, which will be integrated within the Balder area hub to
increase processing and handling capacities across the Balder and Ringhorne
Øst fields. The project's target is to extract an additional c.140 mmboe from
the area and it will also provide expansion capacity to tie in extra wells to
the FPSO after the completion of Balder Future drilling programme.
The upgrade of the Jotun FPSO for the Balder Future development project is
ongoing and the refloat of the vessel occurred in late June 2023. This enabled
the safe completion of the heavy-lift installation of the turret, turntable
and gantry in July. The subsea systems including flowlines, umbilical and
risers have now all been installed, with templates, multi-flow bases,
flowlines and buoyancy elements for risers also in place. Dewatering of the
gas export line and gas lift lines along with flushing of lines and umbilical
testing have all been conducted.
In mid-February 2024, the FPSO refurbishment was reported by the operator to
be more than 90% complete and only slightly behind the revised plan, with the
subsea umbilicals, risers and flowlines (SURF) elements more than 80%
complete (all subsea equipment has been delivered and the majority installed,
with a summer 2024 campaign scheduled to pre-lay risers ready for the FPSO
arrival). Ten out of 14 new production wells have been completed, and all
production wells will be ready for start-up as soon as the Jotun FPSO is
installed in the field and tie-ins are complete. with the operator's current
focus is on executing the remaining construction and commissioning work whilst
drilling and subsea facilities activities are progressing according to
schedule. The operator's targeted start-up date of the FPSO has been moved to
the fourth quarter of 2024, based on an inshore sail away by August 2024.
The United Kingdom
Greater Laggan Area
In July 2022, Kistos marked its entry to the UK Continental Shelf with the
completion of the acquisition of a 20% interest in the GLA from TotalEnergies
E&P UK Limited. As part of the acquisition terms, a contingent
consideration payment of €15.6 million was made in January 2023. This
payment was calculated by reference to the average gas price and GLA
production during 2022.
The average net production rate from the GLA in 2023 was 4,000 boepd, compared
to 6,200 boepd (pro forma) in 2022, reflecting primarily natural reservoir
decline. In addition, production during the year was impacted by a period of
unplanned outages during March as a result of compressor unavailability, a
failure of the monoethylene glycol (MEG) reboiler facilities from August to
November, and by an emergency shut-down and 10-day outage following a heating
medium pipework failure at the SGP in December. Planned activities, which
included approximately three weeks of shut-ins during April to allow for
planned pipeline pigging operations, and a three-day planned maintenance
window during May were completed according to schedule.
Production from the single well on the Edradour field remains suspended due to
facilities constraints relating to MEG management and saw negligible
production during 2023. The GLA joint venture continues to monitor the well
and its potential restart. So far, other GLA wells have compensated for the
production shortfall. Overall GLA output last year was within the original
forecast range until the emergency shut down of the SGP in December 2023.
On a pro forma basis, average realised gas prices fell by 53% to 99p/therm in
2023 from 210p/therm a year earlier. This, combined with the reduction in
average production rates outlined above, resulted in a decrease in revenue to
€99 million from €126 million. Kistos also saw regular liftings of natural
gas liquids (C3, C4 and C5+) and the sale of one parcel of crude oil from the
GLA during 2023.
A series of three 4D seismic surveys were acquired over the producing GLA
fields, with completion occurring ahead of schedule in early July and (due to
favourable weather conditions) significantly under budget. The primary aim of
the campaign is to evaluate potential infill opportunities over Laggan,
Tormore and Glenlivet, and to provide better reservoir monitoring and
management of the GLA as a whole. The acquired seismic is currently subject to
ongoing processing for 3D and 4D applications, and final results are expected
early 2024.
The results of the seismic survey may also help inform JV decisions over the
other future developments, including Edradour West. During the year, the JV
partners continued to progress options for the Edradour West development,
while the Glendronach development previously passed all technical stage gates
with the operator and partners. It is now undergoing a recycling of project
economics following changes to the cost environment since it was originally
assessed. Both of these projects have so far exhibited accretive economics and
would utilise the existing GLA subsea infrastructure and the SGP if they are
approved for development. The JV is also in the initial stages of evaluating
other infill drilling opportunities on the Laggan and Tormore fields.
The nearby Victory development (Shell 100%) is planned to be a single subsea
well tied back to the existing GLA infrastructure and the SGP, with first gas
targeted for the fourth quarter of 2025. The project received regulatory
approval to proceed in January 2024 and, once on-stream, will significantly
reduce unit operating costs for the GLA partners while providing a life
extension for the existing GLA fields.
In 2023, the CO(2) emissions intensity from GLA production (on a Scope 1 and
Scope 2 basis) was estimated at 15 kg CO(2)e/boe (2022: 12 kg CO(2)e/boe),
well below the UK average for offshore gas fields of 25 kg per boe(( 1 )). As
production from the GLA naturally declines in 2024, this intensity ratio is
anticipated to increase. However, it will be reduced again once Victory comes
onstream. The JV partners continue to evaluate and execute energy efficiency
and electrification options at the SGP to further reduce the asset's carbon
intensity.
Benriach
The Benriach exploration well, located on block 206/05c (Kistos 25%), was
spudded on 21 March 2023 by the Transocean Barents drilling rig. A total
measured depth of approximately 4,400 metres was reached and an extensive data
acquisition programme was conducted, including obtaining rotary sidewall
cores, full wireline coverage, live pressures and fluid samples. The campaign
confirmed the presence of gas-bearing sands in the target Royal Sovereign
formation. However, based on initial analysis, the discovered resource is
expected to be sub-commercial and a decision was taken to plug and abandon the
well. Drilling concluded ahead of schedule in June 2023, with zero lost time
incidents or first aid cases and at a post-tax cost net to Kistos of
approximately €4 million. Detailed analysis of the acquired data by the
operator is expected to conclude in the first half of 2024 and has the
potential to benefit nearby developments (such as Glendronach).
Reserves and resources
Kistos exited 2022 with 2P reserves of 12.7 MMboe. Following the acquisition
of the Norwegian interests in May 2023, group 2P reserves at the end of 2023
were 27.9 MMboe.
Pro forma production in 2023 was 3.2 MMboe, while net downwards revisions in
the UK and the Netherlands amounted to 4.5 MMboe, arising from revisions to
subsurface models and taking into account the reduced performance potential of
the single well on the Edradour field.
Our 2C contingent resources are estimated to be 67.5 MMboe at the end of 2023,
including the other opportunities in the Balder area in Norway, Orion and
M10a/M11 in the Netherlands, and Glendronach and Edradour West in the GLA.
Onshore UK gas storage acquisition
In February 2024, we announced an agreement to purchase EDF's onshore gas
storage assets at Hill Top Farm and Hole House in Cheshire, UK, for £25
million payable in cash at completion less closing working capital adjustments
(the 'Gas Storage Acquisition'). The acquisition, which completed in April, is
in line with our strategy to pursue opportunities that align with the energy
transition and provides diversification of our asset portfolio into a stable
marketplace that offers significant growth potential.
Hill Top's working gas capacity is 17.8 million therms, with an ongoing
programme to increase this to 21.2 million therms in the short term. At
current levels, Hill Top accounts for 3.1% of the UK's total available onshore
gas storage capacity. Due to the fast cycle nature of the facility, Hill Top
can deliver up to 11% of the UK's flexible daily gas capacity if called upon.
With the potential reactivation of the Hole House facility, which is currently
non-operational, it would be possible to increase materially our share of the
UK's total onshore gas storage.
Both Hill Top and Hole House have the potential to be repurposed for future
energy storage uses, including the storage of compressed air or hydrogen, and
concept studies are underway. This would place these assets firmly into the
transitional energy space beyond the current key role they play in the UK's
supply of gas.
Peter Mann
Chief Executive Officer
Financial Review
31 December 2023 (actual) 31 December 2023 (pro forma)(( 2 )) 31 December 2022 (actual) 31 December 2022 (pro forma)(8)
Revenue €'000 206,997 223,092 411,512 568,445
Average realised sales price(( 3 )) €/boe 71 71 167 158
Unit opex(( 4 )) €/boe 24 25 10 12
Adjusted EBITDA(10) €'000 120,777 122,319 380,015 517,202
Profit/(loss) before tax €'000 (45,858) n/a 254,125 n/a
Earnings/(loss) per share € (0.30) n/a 0.31 n/a
Net cash from operations €'000 203,159 n/a 290,702 n/a
Net (debt)/cash(10) €'000 (24,319) (24,319) 130,408 130,408
Production and revenue
Actual production on a working interest basis averaged 9,200 barrels of oil
equivalent per day (boepd) in 2023 (2022: 10,600 boepd). This represents a
decrease of 14% from a year earlier and reflects the natural decline in
production from our UK and Dutch assets, unplanned production interruptions in
the Netherlands, partially offset by the inclusion of the Group's interests in
Norway from 23 May 2023.
On a pro forma basis (assuming Kistos had completed the acquisitions of the
GLA interests and Mime on 1 January 2022 and 1 January 2023 respectively),
production was 8,800 boepd (2022: 10,900 boepd). As well as natural decline,
this reduction reflects periods of downtime in the Netherlands during the
drilling campaign in the first quarter of 2023, unplanned production
interruptions following attempted restarts after the planned annual
maintenance at the P15-D platform in the summer, and planned annual
maintenance and pigging campaigns on the GLA in the UK during April. Again,
this was offset by the addition of oil production from the Balder Area in
Norway, which saw increases in production rates as the year progressed as new
wells came onstream at the Ringhorne platform.
The Group's average realised price across gas and oil sales during the period
was €71/boe, and total revenue from gas and oil sales was €207 million,
versus €167/boe and €412 million a year earlier. On a pro forma basis,
these figures were €71/boe and €223 million, a decrease from €158/boe
and €568 million realised in 2022. The 55% reduction in average realisations
was a function of the significant reduction in UK and Dutch gas prices in
2023, with realised oil prices improving slightly as the proportion of the
Group's revenue derived from the sale of crude increased and we received more
frequent payments.
In the Netherlands, the average realised gas price for the year was €43/MWh
(2022: €105/MWh, which included the impact of hedges during the first
quarter of the year). Based on the average 2023 realised price, cijns (a
'windfall' royalty tax) was not payable for the year. In the UK, the average
realised gas price for the period was 99p/therm (2022 pro forma: 210p/therm).
The average realised oil price from crude oil sales in Norway on a pro forma
basis was $80/boe. This was approximately 3% lower than the average Brent
crude price for the period, which was a function of the norm price
differential applied by the Norwegian Petroleum Price Council to Balder crude.
Operating costs
Total adjusted operating costs(( 5 )) (which exclude non-cash accounting
movements in inventory) were €72 million (2022: €27 million). On a pro
forma basis, adjusted operating costs were €82 million (2022: €47
million), with this figure reflecting the inclusion of a full year of
production costs in Norway. On a unit opex basis, pro forma costs were
€25/boe (2022: €12/boe), reflecting higher production costs in Norway,
lower production rates in the UK and Netherlands, and a contracted change from
tariff payments to a cost share arrangement for Q10-A at the TAQA-operated
P15-D platform.
Adjusted EBITDA
€'000 Year ended Year ended
31 December 2023 31 December 2022
Pro forma(( 6 )) Adjusted EBITDA 122,319 517,202
Pro forma adjustment (1,542) (137,187)
Adjusted EBITDA 120,777 380,015
Depreciation and amortisation (99,230) (83,234)
Impairments (59,023) (44,547)
Development expenses (1,146) (1,752)
Transaction costs (2,581) (681)
Share-based payments (159) (538)
Contingent consideration movements 3,355 26,993
Operating profit/(loss) (38,007) 276,256
Adjusted EBITDA was €121 million or €41/boe of production in 2023,
compared with €380 million and €139/boe in 2022. This reduction was caused
primarily by the significant drop in average gas prices year-on-year, in
conjunction with a reduction in overall production rates and higher operating
costs arising from lower production and Norway incurring higher unit operating
costs than our pre-existing assets. The same dynamic resulted in pro forma
EBITDA falling to €122 million or €38/boe of production from €517
million or €130/boe a year earlier. The depreciation charge for the year was
€99 million, equivalent to €33/boe produced (2022: €83 million or
€30/boe produced).
Impairment charges of €59 million were recognised during the year, primarily
relating to the GLA assets, where a sub-commercial result on the Benriach
exploration well (Kistos 25%) and decisions by the JV partners to relinquish
the Roseisle (14%) and Cardhu (20%) licences has resulted in the acquisition
fair values and expenditure post-acquisition being written off. A downwards
revision to reserves in the Netherlands combined with a reduction in European
gas prices triggered an impairment of €13 million against the Q10-A field.
Capital expenditure
Cash capital expenditure in 2023 was €119 million. Of this, €14 million
related to the drilling campaign on Q10-A, which concluded in March 2023.
Capital expenditure on the Benriach exploration well, which spudded in March
2023 and completed operations in June 2023, was €20 million net to Kistos.
This reduced to €4 million on a post-tax basis after taking into account the
investment allowance available under the UK Energy Profits Levy.
In Norway, Kistos' share of cash capital expenditure was €77 million, which
was primarily spent on drilling for the Balder Future project, refurbishment
costs on the Jotun FPSO and associated subsea facilities. Capital expenditure
in Norway is relievable at an effective rate of 78%, with any tax losses
generated during the year creating a tax credit that is receivable as a cash
tax rebate the following December. The receivable in respect of 2023 Norwegian
tax losses (primarily generated by capital expenditure) is anticipated to be
approximately €80 million, to be received in December 2024.
Profit/loss before tax
The operating loss for the period was €38 million (2022: operating profit of
€276 million). After net finance costs of €8 million (2022: net finance
costs of €22 million) principally relating to higher bond interest expense
due to the additional debt assumed as part of the Mime Acquisition, which was
partially offset by associated foreign exchange gains, a loss before tax of
€46 million was recorded (2022: €254 million profit before tax).
Tax
The net accounting tax credit for the period was €21 million, reflecting the
deferred tax benefit of the Benriach well impairment, the EPL investment
allowance on capital expenditure in the UK and pre-tax losses in Norway
arising from the significant capital investment underway on the Balder Future
project. The net current tax credit for the year (representing primarily tax
due or receivable on profits or losses made in the year) was €23 million
(2022: €196 million charge). This is based on the statutory headline rates
of 75%, 78% and 50% in the UK, Norway and the Netherlands respectively, offset
by capital allowances from our drilling campaign at Benriach, the Balder
Future project and the well intervention activity on Q10-A. The prior period
included the impact of the Solidarity Contribution Charge tax, a one-off tax
levied by the Dutch Government on so-called 'surplus profits' generated in
2022.
Net cash tax receipts for the period were €38 million, comprising €34
million payments in the Netherlands offset by a cash tax refund of €72
million in Norway (2022: €66 million net cash tax payments, wholly relating
to the Netherlands).
Balance sheet and liquidity
At the end of 2023, the Group held cash and cash equivalents of €195 million
(31 December 2022, €212 million) and net debt of €24 million (31 December
2022, net cash of €130 million). Pre-tax operating cashflow for the year was
€165 million (2022: €356 million); the reduction reflecting the decrease
in production and realised sales prices offset by a positive working capital
movement arising from settlement of gas sales made in December 2022 when
prices were significantly higher than 2023's averages.
As part of Kistos' acquisition of Mime Petroleum in May 2023, the latter's
outstanding bond debt was restructured. This resulted in Kistos assuming $270
million of debt, including $45 million of Hybrid Bonds. These only become
payable in whole or part if 500 kbbl is offloaded and sold from the Jotun FPSO
by certain dates. In the event this has not been achieved by 31 May 2025, then
no payment will be due under the terms of the hybrid bonds.
The remaining $225 million bond debt is split between a $120 million bond and
a $105 million bond. The former matures in September 2026 and carries a coupon
of 9.75% (4.5% in cash and 5.25% payment in kind). The latter matures in
November 2027 and carries interest at 10.25% wholly payable in kind. At 31
December 2023, the face value of the bonds had increased to $242 million
following the issuance of payment in kind bonds.
During the year, the Group made market purchases of certain amounts of bond
debt issued by its Dutch subsidiary in 2021 as part of the Tulip Acquisition.
Then, in December 2023, it utilised surplus cash on its balance sheet to
exercise a call option to redeem in full the remainder of the bonds. The total
cash cost of bond repurchases in 2023 was €84 million (excluding accrued
interest) and resulted in a net saving of €15 million in scheduled interest
payments to original maturity.
The current tax liability at the end of 2023 was €129 million (2022: €143
million). Both periods include €47 million provided for in respect of the
Solidarity Contribution Tax, for which the Group believes there is a strong
argument that the relevant Dutch subsidiary, Kistos NL2 BV, is out of scope
(see note 6.4 to the Financial Statements). This is because, in its opinion,
less than 75% of its turnover under Dutch GAAP (the relevant measure for Dutch
taxation purposes) was derived from the production of petroleum or natural
gas, coal mining, petroleum refining or coke oven products. Nonetheless, the
settlement of the remaining €82 million of other current tax liabilities
will have a material impact on operating cash flow in 2024.
Due to the significant capital expenditure being incurred on the Balder Future
project, tax losses have been generated in Norway. Unlike the UK and Dutch tax
regimes, whereby tax losses are carried forward and only offset against any
future taxable profits, tax losses in Norway result in cash tax repayments.
After receiving NOK 857 million in December 2023, Kistos expects to receive
over 900 million NOK (€80 million), not including accrued interest, in
December 2024.
Going concern
To assess the Group's ability to continue as a going concern, base case and
downside cash flow forecasts have been prepared which cover a period of at
least twelve months from the approval of this Report.
The forecasts and projections made in adopting the going concern basis take
into account forecasts of commodity prices, production rates, operating and
G&A expenditure, committed and sanctioned capital expenditure, foreign
exchange rates and the timing and quantum of future tax payments and receipts.
Based on the judgments summarised below, and provided in detail within note
1.2 to the Financial Statements (which includes consideration of both
reasonably plausible downside scenarios, and mitigating actions management
could take) these Financial Statements have been prepared on a going concern
basis.
The Group's cash balances as at the end of April 2024 was €80 million. To
assess the Group's ability to continue as a going concern, cash flow forecasts
were evaluated for the period to June 2025 (the going concern period), by
preparing a base case forecast and various downside sensitivity scenarios.
The base case forecast indicated that the Group would be able to maintain a
sufficient amount of liquidity to meet its bond covenant requirement (being a
minimum liquidity of $10 million required to be held within Kistos Energy
Norway) and day-to-day operations across the going concern period.
However, due to the potential for one or more of the reasonably plausible
downside scenarios occurring, and due to their being no guarantee that the
Group would be successful in achieving mitigating actions to remedy the
adverse impact thereof, a material uncertainty exists which may cast
significant doubt about the Group's continued ability to operate as a going
concern and its ability to realise its assets and discharge its liabilities in
the normal course of business. Nonetheless, this Annual Report and Financial
Statements have been prepared on the going concern basis and do not include
any adjustments that may result from the outcome of these uncertainties.
Further information concerning the key assumptions and judgements made in the
assessment of going concern is disclosed in note 1.2 to the Financial
Statements.
Our ESG Goals
In late 2023, we began re-evaluating our ESG goals to explore whether any
adjustments or refinements were needed. We have now developed a revised set of
ESG goals for 2024.
We concluded that some of our previously published goals were no longer
aligned with our evolving business while others were not applicable at a Group
level. We have therefore developed, approved and published a revised set of
ESG goals, which will apply from 2024.
We believe the following ESG goals more accurately align with our current
business strategy and will allow both Kistos and our stakeholders to measure
progress across our strategic operations more effectively.
Caring for the environment
Achieve carbon neutrality for Scope 1 and 2 emissions by 2030.
Maintain zero operational spills annually in our operated sites(( 7 )).
Maintain zero hazardous contaminants in discharges to water annually in our
operated sites(7).
Incorporate nature-inclusive design principles into new operated
projects(7).
Putting people first
Achieve zero harm to workers annually in our offices and operated sites(7).
Recruit from a diverse, qualified group of candidates to increase range of
thinking and perspective.
Foster a culture that encourages collaboration, flexibility and fairness to
enable all employees to contribute to their potential and increase retention.
Embed diversity and inclusion in policies and practices, and equip leaders
with the ability to manage diversity and be accountable for the results.
Our ESG Performance
We manage the ESG issues associated with our Group through responsible and
sustainable business practices.
Environment
We believe that natural gas and oil have an important role to play in the
energy transition, bridging the gap on the journey from fossil fuels to a
renewable, zero-carbon future. In the short term, there is unlikely to be
sufficient renewable energy to fully meet demand so developing and extracting
oil and gas contributes to the security of supply in the meantime. The
emissions intensity and the carbon footprint of future projects are actively
evaluated, reflected in the decision making related to potential acquisitions,
and also included as part of ongoing operational and project decisions.
Our recently announced acquisition of onshore gas storage assets in the UK
means that we will be able to further contribute to the security of energy
supply in the UK. The assets have around 3% of the UK's total available
onshore gas storage capacity and up to 11% of the UK's flexible daily gas
capacity if called upon. The assets also have the potential to be repurposed
for future energy storage, including the storage of compressed air or
hydrogen. As well as enhancing Kistos' current place in the traditional energy
space, these new assets could be potentially deployed to support the energy
transition in the future.
Direct emissions and air quality
In 2023, our operations included drilling infill wells offshore the
Netherlands at the start of the year. And in the UK, we worked with operator
TotalEnergies to drill the Benriach exploration well west of Shetland in the
second quarter. Drilling work in Norway was ongoing, with six wells drilled
and completed as part of the Balder Future campaign, and a further five
Ringhorne Phase IV wells drilled from the Ringhorne drilling platform.
One of our new ESG goals is to achieve carbon neutrality for Scope 1 and Scope
2 emissions by 2030. Our Scope 1 emissions levels (from our operated assets)
are minimal, thanks to the solar panels and wind turbines that power the Q10-A
platform. Due to declining production levels from the Q10-A wells in 2023
compared to 2022, our Scope 1 emissions intensity increased year-on-year.
However, we saw a reduction in the absolute level of Scope 1 emissions due to
the increased capacity for generating renewable energy on the platform - see
case study.
Our Scope 2 emissions primarily relate to the combustion of gas in compressors
on the P15-D platform for processing and exporting the gas produced from
Q10-A.
Actual emissions from operated assets
kg CO(2)e/boe 2023 2022
Scope 1 Excluding flaring <0.01 <0.01
Including flaring 0.37 0.28
Scope 1 and Scope 2 Excluding flaring 18.5 13.8
Including flaring 18.9 14.1
Tonnes CO(2)e 2023 2022
Scope 1 Excluding flaring 3 5
Including flaring 643 855
Scope 1 and Scope 2 Excluding flaring 32,261 42,393
Including flaring 32,901 43,243
We don't flare as part of our routine production operations, and only permit
it when starting up or closing down to depressurise systems, and from operated
rigs during drilling and well-intervention campaigns. Even then, we have
improved these processes to make them more carbon efficient. We have also
implemented a programme to identify and prevent methane leaks from our
operations with annual inspections, exceeding the four-year inspection
requirement.
Across the Q10-A platform in the Netherlands, as well as our non-operated
interests in the Greater Laggan Area (GLA) offshore the UK and on the
Norwegian Continental Shelf (NCS), the Group's Scope 1 and Scope 2 emissions
are significantly below the North Sea average. They are also estimated to be
significantly lower than the average CO2 emissions intensity associated with
the import of liquefied natural gas (LNG), estimated by the North Sea
Transition Authority (NSTA) as being 79 kg CO(2)/boe(( 8 )).
Operational energy use
The Q10-A platform is unmanned and is powered using renewable energy generated
by solar panels and wind turbines. Compared to using diesel generators, Kistos
estimates this saved approximately 21 tonnes of CO2 emissions per year.
Similarly, we estimate that our policy of conducting offshore visits via boat
rather than helicopter saved more than 15 tonnes of CO2 emissions in 2023.
In Norway, the Balder FPU is relatively old and uses about 100,000 tonnes of
diesel per year. As part of the Balder Future project, this vessel will be
retired from the field by 2030 at the latest, with the newer and more
efficient Jotun FPSO moving onto station and eventually taking over the
processing and storage of all production from the Balder field. We are also
working closely with Vår Energi on electrification-from-shore options for the
wider Balder/Grane area.
Spills and incidents
Recognising that spills and incidents is one of our main material issues, we
have set ourselves a goal to maintain zero operational spills annually in our
operated sites.
We have robust processes in place to prevent major accidents and avoid
spillages at sea, as well as clearly defined mitigation and clean-up
procedures should an unexpected incident occur. For our operated assets, we
are obliged to have an emergency response team available around the clock and
we take part in emergency response exercises run by the operator for our other
assets.
During 2023, we experienced no spills or loss of containment within our
operated assets. In December 2023, we experienced an unplanned shutdown of
operations at the Shetland Gas Plant (SGP) following a failure of the heating
medium system. This resulted in a release of steam, with no harm to personnel.
We worked closely with the operator TotalEnergies during and after the
incident to understand the root causes of the failure while also acknowledging
the strong performance by the operator on its incident management and
communication.
Effluents and waste
In line with the strict regulations governing our sector, one of our revised
ESG goals is to maintain zero hazardous contaminants in discharges to water
annually in our operated sites.
We strictly adhere to guidelines, compliant with EU REACH regulations, that
prevent the use of certain chemicals and materials that are considered harmful
to the environment.
Biodiversity
In working towards our stated ESG goal to incorporate nature-inclusive design
principles into new operated projects, we aim to use building materials and
construction methods that promote local habitats where feasible.
Furthermore, we employ people to watch bird migrations and inform us when
flaring can be conducted safely without affecting birds and other local
wildlife. We also limit the ultrasonic sounds from our operations to prevent
harm to marine life and take specialist advice to keep seals away from our
offshore platforms.
Social
Health and safety
Reflecting its importance as one of our most material issues, we have revised
our relevant ESG goal for health and safety. We now define our aim as being to
achieve zero harm to workers annually in our offices and operated sites.
Having incorporated third-party contractors into our safety culture, our HSE
performance remains strong. In pursuit of our zero-harm goal, we had zero lost
time incidents (LTI), zero incidents of non-compliance, one near miss and zero
identified (non-reportable) hazards during the three months of drilling and
testing operations in 2023.
We already have strict protocols and rigorous testing procedures in place to
keep our employees and contractors safe, but we continue to make improvements
where we can.
· In 2023, we established a Process Safety Management Standard.
This comprises 15 requirements for managing the main risks across our operated
and non-operated assets. This standard covers activities for safeguarding the
integrity of wells, pipelines and facilities associated with Major Accident
Hazards (MAHs). The requirements are grouped under four categories: risk
management; design and construction; operations, inspection and maintenance;
and process safety culture.
· We also replaced our 12 safety rules with the International
Association of Oil & Gas Producers' (IOGP) nine Life-Saving Rules in 2023.
By adopting these industry-wide actions - which cover topics such as driving,
confined spaces, energy isolation and working at height - we have simplified,
expanded and added to the controls we use to keep everyone safe while at work.
These Life-Saving Rules are combined with our 13 Start-Work Checks, which help
workers verify that the necessary controls and safeguards are in place before
starting a task.
Looking ahead to 2025, when our Dutch subsidiaries will need to report in line
with the new Corporate Sustainability Reporting Directive (CSRD), we are
already aligning our businesses in the UK, the Netherlands and Norway under a
five-year HSE plan. As well as having annual plans for asset integrity and
process safety, we now have a timeline for improving HSE leadership,
certification, contractor management, and behavioural safety programmes that
runs to 2028.
Workplace culture
Our revised ESG goals now include our ambition to foster a culture that
encourages collaboration, flexibility, and fairness to enable all employees to
contribute to their potential and increase retention.
We have retained a flexible working environment for all employees. However, we
remain mindful of the need for direct interactions and networking to support
the professional development of our people.
We encourage employees to seek out relevant training courses that will further
their professional development and provide benefits to the Group. We will
cover the cost of such courses and grant employees time off to attend courses
that are relevant or appropriate to the role.
Diversity, equality, and inclusion
The importance we place on diversity, equality, and inclusion (DEI) is
reflected in two of our ESG goals. As well as recruiting from a wide range of
candidates to increase diversity of thinking and perspective, we also intend
to identify and break down systemic barriers to full inclusion by embedding
diversity and inclusion in policies and practices and equipping leaders with
the ability to manage diversity and be accountable for the results. When
hiring, we do not discriminate on grounds of disability, ethnicity or gender;
and offer the same access to training to all employees regardless of
background or situation.
As we have a relatively small number of employees across the organisation,
each role is unique within its region. It is therefore not meaningful to
measure the pay gap across genders. When seeking to fill new roles, we offer
remuneration packages commensurate with level, experience and technical
expertise required, and do not consider the gender of the applicant.
Human rights
Kistos recognises its responsibility to respecting human rights in all aspects
of doing business and we have embedded human rights in our Code of Business
Conduct and in our Modern Slavery Statement. We believe that an integrated
approach to human rights, embedded into our policies, business systems and
processes, allows us to efficiently and effectively manage human rights within
our existing ways of working. Our approach applies to all our employees and
contractors. We focus on four areas where respect for human rights is
particularly critical to the way we operate: labour rights, communities,
supply chains, and security. We have community feedback mechanisms at all our
major facilities. These mechanisms enable employees, people in the communities
where we operate, contractors and any third party to raise concerns, so they
can be resolved, enabling us to meet our commitment to provide access to
remedy.
Principal Risks and Risk Management
Kistos identifies, assesses and manages the risks critical to its success.
The Group's business, people and reputation are safeguarded by overseeing
these risks. We use the risk management process to ensure that we are aware,
and in control, of the risks we face. This way, we can achieve our strategic
goals and create value. We may choose to accept, manage, transfer or remove
the risk depending on its nature. We may manage the risk with controls or
other actions that reduce its impact. We may transfer the risk to others who
can handle it better. Or we may remove the risk by stopping the activities
that cause it.
Management maintains a Corporate Risk register based on risks identified at
asset and business level, which includes the underlying risks and mitigating
actions for each. This is reviewed by senior management, the executive
directors, the Audit Committee, and the Board.
The principal risks facing the Group, and the actions taken to minimise their
likelihood and/or mitigate their impact, are listed in the following table.
The Directors confirm they have conducted a thorough assessment of the main
risks that affect the Group, including those that would significantly harm its
strategy, business model, future performance or liquidity.
(A) Political
Changes in national government policies towards oil and gas-focused companies
could adversely impact the ability of the Group to deliver its strategy.
Change in risk level: Increase Owner: Peter Mann (CEO)
Potential impact Mitigation Risk movement
· Refusal of permitting applications for development, appraisal and · Active member of Element NL, OEUK, BRINDEX, Offshore Norge and other This risk has increased in 2023:
exploratory drilling. industry associations.
· Changes in the Dutch political landscape occurred in 2023.
· Increased costs relating to permitting and legal matters, and delay to · Engagement with the respective governments and other appropriate
projects. organisations to ensure the Group is kept abreast of expected political · A General Election is anticipated in the UK later in 2024, which may
changes. result in a change in government.
· Impairment of intangible assets.
· Active role taken in making appropriate representations to the relevant
· Inability to win new licences. departments in governments.
· Loss of value to stakeholders.
(B) Growth of business and reserves base
The Group's growth strategy is primarily dependent on identifying new reserves
and resources, and is delivered through development and acquisition. Organic
growth is focused on developing existing resources into producible reserves. A
focus on growth of the business and the reserves base outside of existing
assets to increase immediate perceived shareholder value may give rise to
missed opportunities and reduced capital allocation to the existing portfolio.
As part of this growth strategy, there is a risk that the Group may fail to
identify attractive acquisition opportunities, acquire businesses without
performing appropriate due diligence or select inappropriate exploration work
programmes. Exploration drilling may deliver adverse results due to factors
including poor quality (or misinterpretation of) data,
failure/underperformance of offshore vessels or other crucial equipment,
unforeseen problems occurring during drilling and delays to offshore
operations due to unfavourable weather. Long-term commodity price forecasts
and other assumptions used when assessing potential projects and investment
opportunities can have a significant influence on the forecast return on
investment. Any expansion into new markets, such as onshore gas storage, may
give rise to lower than expected returns due to unfamiliarity with the
relevant activities and higher than anticipated integration costs.
Change in risk level: Increase Owner: Andrew Austin (Executive Chairman)
Potential impact Mitigation Risk movement
· Reduced asset value, leading to potential impairment of oil and gas · A broad range of acquisitions and similar opportunities are evaluated This risk has increased in 2023:
assets, and/or intangible exploration and evaluation assets. internally, with support from subject matter experts where appropriate. Such
targets are scrutinised by the Board, including the Non-Executive Directors, · The Group maintains its strategy of securing additional reserves.
· Actual or perceived overpayment for acquisitions, leading to impairments who challenge the Executive team and other senior management.
of goodwill and assets.
· The upstream M&A environment, whilst still remaining active on a
· Strong relationships are maintained within the industry. global scale, has seen fewer attractive opportunities arising in the UK and
· Adverse reputational and share price impact.
Netherlands.
· A rigorous assessment process evaluates and determines the risks
associated with all potential business acquisitions and strategic alliances,
including conducting stress-test scenarios for sensitivity analysis. If
applicable, each assessment includes an analysis of the Group's ability to
operate in a new jurisdiction.
· Country managers and senior team members with responsibility for
activities attend weekly senior management meetings, where concerns can be
raised and the status of current business development projects is updated.
· Exploration, appraisal and development cases are robustly assessed and
stress tested against cost, price and taxation sensitivities.
(C) Climate change and energy transition
Changes in laws, regulations, policies, obligations and social attitudes
relating to the transition to a lower carbon economy could lead to higher
costs, or reduced demand and prices for oil and gas, impacting the
profitability of the Group. Sources of debt and equity finance may become more
expensive or restricted as investors diversify away from oil and gas-based
investments. Climate change may result in an increase in the frequency of
severe adverse weather conditions.
Change in risk level: No change Owner: Peter Mann (CEO)
Potential impact Mitigation Risk movement
· Increased difficulty in accessing finance due to reduced appetite for · Active reviews of the Group's strategy towards energy transition, with an No change in 2023:
investing in the oil and gas industry. aim to provide long‑term returns to shareholders, and consideration of the
impact of climate change and potential changes to policy in decision making. · Although climate change and energy transition remain a key focus for the
· Increased difficulty in obtaining regulatory approval for new or
Group, limited adverse impact has been experienced with regards to the
increased offshore production activities. · Environmental considerations are a key factor in determining any availability of financing opportunities and wider hydrocarbon demand. This is
potential inorganic growth activity. expected to remain in the short- to medium-term.
· Stranded assets.
· Value of projects is discounted in the future for later life production
· Adverse impact on operating cash flow due to higher carbon credit costs. to take into account possible reduced demand for hydrocarbons.
· Disruption to operations from extreme weather events may result in · Stress tests of budgets and forecasts in respect to the cost of carbon
shut-ins, physical damage to assets, lost production and reduced cash flow. emission allowances.
· Continue to investigate and implement actions that could reduce the
Group's environmental footprint, where it makes commercial and financial sense
to do so.
· Design and operate assets to work in the majority of weather conditions
and undertake lessons learnt when storms and other events disrupt production.
· Working closely with operators and partners to understand and manage
planning, production forecasting.
(D) Cyber security
There is a risk of financial loss, reputational damage and general disruption
from a failure of the Group's IT systems or an attack for the purposes of
espionage, extortion, terrorism or to cause embarrassment. Any failure of, or
attack against, the Group's IT systems may be difficult to prevent or detect,
and the Group's internal policies to mitigate these risks may be inadequate or
ineffective. The Group may not be able to recover any losses that arise from a
failure or attack.
As the Group grows, there are more IT areas to standardise and migrate up to
Group standards. In interim periods, there is an increased risk of incidents
until such time as policies and standards are fully aligned.
Change in risk level: Increase Owner: Richard Slape (CFO)
Potential impact Mitigation Risk movement
· Financial loss from phishing attacks that may not be recovered. · Outsourcing of the provision of IT equipment and help-desk services to This risk has increased in 2023:
competent and experienced third parties.
· Reputational impact from leak of market-sensitive data or personal
· Higher level of attempted cyber security incidents experienced to date.
information. · Robust network management systems in place to protect the Group's IT
environment. · Business acquisitions give rise to diverse IT systems, bringing
· Fines and financial penalties may be levied in the event of a data
additional risk before, during and after integration.
breach. · Well-designed IT security management model with defensive structural
controls.
· Set of rules and procedures in place, including a Disaster Recovery Plan,
to restore critical IT functions.
· Regular mandatory staff training and awareness of cyber security matters
such as phishing attacks.
· Following any acquisition, plans in place to move acquired businesses
onto common IT platforms as soon as possible, using its IT contractor to
undertake assessments, gap analyses and on-site audits.
· A detailed understanding of IT environment on any potential acquisition
target is typically obtained during due diligence to assess level of current
risk (if unacceptable, transactions may not go ahead).
(E) Joint venture activity
As a minority non-operating partner in the GLA and Balder partnerships,
operated by TotalEnergies and Vår Energi respectively, the interests and
objectives of the partners may not be aligned.
Change in risk level: Increase Owner: Peter Mann (CEO)
Potential impact Mitigation Risk movement
· Longer decision-making processes resulting in loss of asset value. · Representation and active participation in all of the joint ventures' This risk has increased in 2023:
committees (including operating, finance and technical).
· Impairment of oil and gas assets, and exploration and evaluation assets.
· The Mime acquisition has resulted in the Group being a minority partner
· Regular engagement with the joint venture operator and other participants in another joint venture.
· Reduction in reserves and resources. with regards to key decision making, preparation and approval of work
programmes and budgets, and general strategic direction. · However, with a non-blocking vote in its non-operated interests, the
· Capital diverted into projects and developments not aligned with Group Group is always at risk of being voted into decisions with which it does not
strategy. agree.
· Inability to meet joint venture cash calls, which may ultimately mean
breach of joint operating agreements (JOAs) and loss of licence.
(F) HSE and compliance
The Group is exposed to various risks in relation to HSE, compliance,
planning, environmental, regulatory, licensing and other permitting rules
associated primarily with production operations, drilling and construction.
There is a risk that the Group and/or its primary contractors are in breach of
their regulatory obligations with one of the principal regulators in
connection with the Group's activities, whether operational (for example,
maintaining offshore production consents or a loss of hydrocarbon containment)
or corporate (for example, adhering to listing rules and market disclosure
regulations). This could restrict the Group and/or its primary contractors'
capacity to obtain permits or carry out the Group's activities.
Change in risk level: Increase Owner: Peter Mann (CEO)
Potential impact Mitigation Risk movement
· Injuries to workforce. · Working closely with regulators to ensure that all required planning This risk has increased in 2023:
consents and permits for operations are in place. Maintenance of continual
· Harm to the environment. dialogue with all stakeholders to understand emerging requirements. · The Group is now operating in a new jurisdiction following the Mime
acquisition.
· Physical damage to assets and infrastructure. · Conducting activities in accordance with Board-approved policies,
standards and procedures. · Increased level of offshore operations and regular oil tanker liftings
· Financial or other penalties imposed.
have a greater potential for HSE incidents.
· Code of Business Conduct and compliance programmes in place to provide
· Reputational damage. assurance on conformity with relevant legal and ethical requirements. · Greater focus from regulatory bodies on compliance matters in current
environment.
· Loss of licence to operate. · Emergency response plans in place and exercises undertaken to prepare for
incidents.
· External consultants with experience in managing risk developments
employed to help complement the existing team skills.
· Audit and Disclosure Committees.
(G) Hydrocarbon production and operational performance
The Group's production volumes (and therefore revenue) are dependent on the
operational performance of its producing assets. The Group's producing assets
are subject to operational risks, including, but not limited to, compressor
failures, lack of sufficient critical chemical stocks and spare parts, failure
of electrical power supply lines, pipeline corrosion, asset integrity and
health, safety, security and environment incidents; and low reserves recovery
from the field and exposure to natural hazards such as extreme weather events.
Change in risk level: Decrease Owner: Peter Mann (CEO)
Potential impact Mitigation Risk movement
· Reduced cash flow from operations. · Continuous review of production performance from each asset, facilitating This risk has decreased in 2023:
performance planning well intervention activities as needed.
· Increased cash costs per barrel equivalent.
· Following the acquisition of interests in Norway, the Group's production
· To the extent possible, discussions held with third parties to manage base is further diversified and thus is no longer exposed to single points of
· Earlier cessation of production if operational performance issues cannot shutdowns both planned and unplanned. failure.
be rectified economically.
· Planned and unplanned downtime assumptions built into the corporate
· Impairment of assets and loss of stakeholder value. budgeting cycle and cash flow projections.
(H) Project delivery
There is a risk of delays in project delivery and higher costs being incurred,
especially under the current high inflationary environment. Continued delays
to the Balder Future project risk material cost increases and potential
additional delay to first oil.
Change in risk level: Increase Owner: Peter Mann (CEO)
Potential impact Mitigation Risk movement
· Delayed and/or reduced cash flow from operations, leading to an inability · Projects have a clear project delivery framework with a responsible This risk has increased in 2023:
to adequately finance other future developments. project lead.
· Operator progress on the Balder Future project, and in particular upgrade
· Impairment of assets. · Delivery against project objectives, timeline and cost are regularly of the Jotun FPSO, has consistently fallen behind schedule and over budget,
monitored. giving rise to a risk of further delay to the projected first oil date.
· Reduction in reserves and resources.
· Project costs are stress tested against cost increases with adequate
contingency built in to estimates.
· Cash flow risk on the Balder project is partially mitigated via the
Hybrid Bond structure, whereby the Hybrid Bond will be released in full if
Balder Future first oil is delayed beyond May 2025.
(I) Retention of key personnel
The Group may not be able to retain key personnel, and there can be no
assurance that it will be able to continue to attract and retain all personnel
suitably qualified and competent necessary for the safe and efficient
operation and development of its business. Share options previously granted
may be out of the money, reducing incentives for staff to remain with the
Group.
Change in risk level: Increase Owner: Peter Mann (CEO)
Potential impact Mitigation Risk movement
· Delay to, or cancellation of, projects as a result of lack of · The Board seeks to cultivate a safe, respectful working environment where This risk has increased in 2023:
appropriately qualified employees to undertake activities. people can thrive.
· Current share prices means employee share options granted in 2022 and
· Loss of 'corporate knowledge' through lack of staff retention, leading to · Benchmarking exercise undertaken by management on reward packages to 2023 are now out of the money.
inefficiencies, delays and increased cost. ensure that acquired staff are retained through a strong remuneration culture.
· Increased competition for qualified staff seen in adjacent green
· Workplace surveys undertaken to ascertain morale and employee concerns industries, such as CCUS.
and allow management to swiftly address any issues.
· Long-term share incentive plans in place are regularly reviewed by the
Remuneration Committee.
(J) Commodity price
The Group's cash flow and results are heavily dependent on natural gas and
other commodity prices. These, in turn, are dependent on several factors
including the impact of climate change concerns, geopolitics (including events
such as the Russia-Ukraine and Israel-Palestine conflicts and other unrest in
the Middle East impacting shipping activities) and regulatory developments.
Change in risk level: No change Owner: Richard Slape (CFO)
Potential impact Mitigation Risk movement
· Adverse impact on operating cash flow. · Oil and gas markets continuously reviewed by the Board to determine No change to this risk in 2023:
whether future hedges are needed.
· Impairment of oil and gas assets.
· Gas prices are lower compared to prior year but still higher than
· Necessary contracts in place to undertake hedging activities if required. historic norms.
· Inability to meet bond covenants or repay debt.
· Cash flow projections, liquidity analyses and economic models regularly · Market no more or less volatile compared to prior year.
· Restricted access to financing opportunities in case of a sustained tested for downside price scenarios.
low-price environment.
· Volatility provides increased opportunity to generate profits from gas
· Exercises undertaken to identify cost reduction and rationalisation storage trading activity.
opportunities to optimise operating cost per barrel (while maintaining safe
and compliant operations).
(K) Liquidity
Adverse changes to production, commodity prices, taxation and surety bond
requirements may put pressure on the Group's available liquidity, constraining
its options to grow the business or meet obligations to joint venture
partners, suppliers and tax authorities. In extreme downside cases, liquidity
pressures may result in minimum liquidity covenants being breached and risk of
insolvency.
Change in risk level: Increase Owner: Richard Slape (CFO)
Potential impact Mitigation Risk movement
· Inability to pay suppliers, contractors and employees as liabilities fall · Regular review of the Group's cash forecasts and its covenants to ensure This risk has increased in 2023:
due, leading to reputational damage and withdrawal of services. an adequate headroom of cash availability.
· Bond debt issued by Kistos NL2 has been fully redeemed, removing those
· Non-payment of taxes as they fall due may result in investigations or · Engagement and strong relationships with the bond market, surety bond bond covenants and reducing future interest cash outflows.
stringent penalties charged. providers and other potential providers of finance to manage access to
liquidity if required. · Redeeming Kistos NL2's bonds has materially reduced the overall cash
· Inability to meet bond covenants or repay debt leading to restructuring, position.
shareholder dilution or insolvency.
· Material additional debt has been taken on as part of the Mime
acquisition, and there is a reduced level of cash headroom overall.
(L) Decommissioning costs and timing
The future costs and timing of decommissioning is a significant estimate; any
adverse movement in price, operational issues, or reductions in reserves and
resource estimates could have a significant impact on the cost and timing of
decommissioning. Where decommissioning costs are to be shared as part of a
joint venture, the Group is exposed to the risk of partners not fulfilling
their commitments. Changes to commodity prices, the taxation regime, inflation
rates and other factors may mean that the Group is not able to renew its
surety bonds in respect of its DSA obligations, resulting in the Group having
to cover its obligations fully in cash and restricting the amount of funds
available for other opportunities and day-to-day operations. Significant
adverse changes to cash flows may result in insufficient resources to meet its
decommissioning obligations, exposing the Group to sanction from regulators.
Change in risk level: No change Owner: Richard Slape (CFO)
Potential impact Mitigation Risk movement
· Reduction in cash flows available for other projects if decommissioning · In-house decommissioning experience, coupled with focus on delivering No change to this risk in 2023:
costs materially exceed estimates. asset value to defer abandonment liabilities.
· Underlying nature of decommissioning risks remain unchanged.
· Adverse reputational, regulatory and legal impact if decommissioning · Decommissioning security arrangements and postings in place for UK
obligations cannot be fulfilled. assets, which mitigate risk from a regulatory and joint-venture partner
perspective.
· Strong relationships with surety bond providers and confidence that the
surety market can continue to provide security for the expected DSA
provisions.
(M) Taxation
Longer-term additional and increased taxes imposed on oil and gas companies by
governments, in reaction to so-called 'windfall profits' arising from
short-term movements in commodity prices, have led to a higher tax burden.
Uncertainty over tax regimes may also hinder future investment decisions and
reduce the returns from, and profitability of, operations. Should the Dutch
tax office rule unfavourably against the Group with regards to the Solidarity
Contribution Tax, this would have a material impact to the Group's liquidity.
Change in risk level: No change Owner: Richard Slape (CFO)
Potential impact Mitigation Risk movement
· Material adverse impact to liquidity position if adverse finding received · Engagement with various industry bodies to raise concerns and suggest No change to this risk in 2023:
with regards to Solidarity Contribution Tax. alternative approaches to proposed taxation policies.
· Taxation regimes have, on the whole, been more stable than in 2022, when
· Retrospective taxation or material changes to tax regimes may render · Projects and liquidity projections modelled with various tax governments hastily introduced adverse tax changes in response to higher
currently economic projects unviable, forcing earlier cessation of production sensitivities in place. commodity prices.
(and reducing overall government tax take), giving rise to asset impairment
risk. · Support and advice of external experts and legal counsel on taxation · Risk remains that tax take remains elevated, even in a lower commodity
matters, including the Solidarity Contribution Tax, is regularly obtained for price environment.
· An increase in jurisdictions with higher tax rates and unpredictable tax areas where significant uncertainty and judgement exists.
regimes may reduce the hopper of available acquisition and expansion
opportunities. · Our investment strategy is continuously reviewed, and decisions may be
taken to not invest further in, or to withdraw from, jurisdictions with a
recent history of significant adverse tax changes, implementation of
retrospective taxation, or where the taxation regime proves too burdensome.
Consolidated Financial Statements
Consolidated income statement
€'000 Note Year ended 31 December 2023 Year ended 31 December 2022
Revenue 2.1 206,997 411,512
Other operating (expense) income (188) 11
Exploration expenses (2,194) (374)
Production costs (72,888) (22,927)
Development expenses (1,146) (1,752)
Abandonment expenses (1,693) -
General and administrative expenses 3.2 (11,997) (9,426)
Depreciation and amortisation 2.4, 2.5 (99,230) (83,234)
Impairment 2.6 (59,023) (44,547)
Change in fair value and releases of contingent consideration 2.8.2 3,355 26,993
Operating (loss)/profit (38,007) 276,256
Interest income 3.5 9,296 267
Interest expenses 3.5 (28,771) (11,283)
Other net finance income/(costs) 3.5 11,624 (11,115)
Net finance costs (7,851) (22,131)
(Loss)/profit before tax (45,858) 254,125
Tax credit/(charge) 6.1 21,177 (181,229)
Solidarity Contribution Tax charge 6.4 - (46,935)
Total tax credit/(charge) 6.1 21,177 (228,164)
(Loss)/profit for the period (24,681) 25,961
Basic earnings per share (€) 3.1 (0.30) 0.31
Diluted earnings per share (€) 3.1 (0.30) 0.31
Consolidated statement of other comprehensive income
€'000 Note Year ended 31 December 2023 Year ended 31 December 2022
(Loss)/profit for the period (24,681) 25,961
Items that may be reclassified to profit or loss:
Losses on cash flow hedges 5.6 - (9,404)
Hedging losses reclassified to profit or loss 5.6 -- 21,185
Income tax on items of other comprehensive income 5.6 - (5,891)
Foreign currency translation differences 5.6 93 (43)
Total other comprehensive income (24,588) 31,808
Consolidated balance sheet
€'000 Note 31 December 2023 31 December 2022
Non-current assets
Goodwill 2.5 49,154 10,913
Intangible assets 2.5 31,315 43,338
Property, plant and equipment 2.4 411,901 282,474
Deferred tax assets 6.2.2 1,932 566
Investment in associates 62 61
Other long-term receivables 149 102
494,513 337,454
Current assets
Inventories 4.5 20,473 9,688
Trade and other receivables 4.2 26,463 54,562
Current tax receivable 6.3.1 80,409 -
Cash and cash equivalents 4.1 194,598 211,980
321,943 276,230
Total assets 816,456 613,684
Equity
Share capital and share premium 5.4 9,464 9,464
Other equity 5.5 3,672 -
Other reserves 5.6 60,239 59,987
Retained earnings 8,580 33,261
Total equity 81,955 102,712
Non-current liabilities
Abandonment provision 2.3 209,041 123,503
Bond debt 5.1 215,722 80,800
Deferred tax liabilities 6.2.1 130,453 118,325
Other non-current liabilities 4.4 613 4,197
555,829 326,825
Current liabilities
Trade payables and accruals 4.3 40,256 21,317
Other current liabilities 4.4 5,627 17,111
Current tax payable 6.3.2 128,616 143,134
Abandonment provision 2.3 4,173 2,585
178,672 184,147
Total liabilities 734,501 510,972
Total equity and liabilities 816,456 613,684
A reclassification to the presentation of certain prior period amounts has
been made - see note 1.5.
The notes below are an integral part of these Financial Statements and were
approved by the Board of Directors on 10 May 2024.
Andrew Austin Executive Chairman
Consolidated statement of changes in equity
€'000 Share capital and share premium Other equity Other reserves Retained earnings Total equity
(note 5.4) (note 5.5) (note 5.6)
At 1 January 2022 103,808 - 9,226 (42,463) 70,571
Profit for the period - - - 25,961 25,961
Other comprehensive income - - 5,847 - 5,847
Total comprehensive income for the period - - 5,847 25,961 31,808
Capital reduction (35,266) - (14,734) 50,000 -
Share-based payments - - 538 - 538
Capital reorganisation (59,078) - 59,110 (237) (205)
At 31 December 2022 9,464 - 59,987 33,261 102,712
Loss for the period - - - (24,681) (24,681)
Other comprehensive income - - 93 - 93
Total comprehensive income for the period - - 93 (24,681) (24,588)
Share-based payments (note 3.4) - - 159 - 159
Issue of warrants (note 5.5) - 3,672 - - 3,672
At 31 December 2023 9,464 3,672 60,239 8,580 81,955
Consolidated cash flow statement
€'000 Note Year ended 31 December 2023 Year ended 31 December 2022
Cash flows from operating activities:
(Loss)/profit for the period after tax (24,681) 25,961
Tax (credit)/charge 6.1 (21,177) 228,164
Net finance costs 3.5 7,851 22,131
Depreciation and amortisation 2.4, 2.5 99,230 83,234
Impairment 2.6 59,023 44,547
Change in fair value and releases of contingent consideration 2.8.2 (3,355) (26,993)
Share-based payment expense 3.4 159 538
Income tax paid (33,794) (65,729)
Income tax received 72,101 -
Interest income received 9,270 229
Abandonment costs paid 2.3 (1,941) (2,319)
Decrease/(increase) in trade and other receivables 36,867 (1,382)
Decrease in trade and other payables (1,131) (13,094)
Decrease/(increase) in inventories 4,402 (4,717)
Movement in other working capital items 335 132
Net cash flow from operating activities 203,159 290,702
Cash flows from investing activities:
Payments to acquire tangible and intangible fixed assets (119,318) (19,454)
Net cash acquired in Mime Acquisition 2.8 7,284 -
Consideration paid for GLA Acquisition 2.8.1 (16,219) (40,047)
Contingent consideration payments 2.8.2 - (7,500)
Net cash flow from investing activities (128,253) (67,001)
Cash flows from financing activities:
Interest paid (11,720) (11,566)
Repurchase and redemption of bond debt 5.1.1 (83,599) (71,773)
Lease repayments and other financing cash flows (1,296) (477)
Net cash flow from financing activities (96,615) (83,816)
(Decrease)/increase in cash and cash equivalents (21,709) 139,885
Cash and cash equivalents at start of period 4.1 211,980 77,288
Effects of foreign exchange rate changes 4,327 (5,193)
Cash and cash equivalents at end of period 4.1 194,598 211,980
A reclassification to the presentation of certain prior period amounts has
been made - see note 1.5.
Notes to the Consolidated Financial Statements
Section 1 General information and basis of preparation
Kistos Holdings plc (the 'Company') is a public company, limited by shares,
incorporated and domiciled in the United Kingdom and registered in England and
Wales under the Companies Act 2006 (registered company number 14490676). The
nature of the Company and its consolidated subsidiaries' (together, the
'Group') operations and principal activity is the exploration, development and
production of gas and other hydrocarbon reserves principally in the North Sea
and creating value for its shareholders through the acquisition and management
of companies or businesses in the energy sector.
1.1 Basis of preparation and consolidation
The Financial Statements have been prepared under the historical cost
convention (except for derivative financial instruments and certain financial
liabilities, which have been measured at fair value) in accordance with
UK-adopted International Accounting Standards, in conformity with the
requirements of the Companies Act 2006 and in accordance with the requirements
of the Alternative Investment Market (AIM) Rules.
These Financial Statements represent results from continuing operations, there
being no discontinued operations in the periods presented.
The accounting period of these consolidated Financial Statements is the
calendar year 2023, which ended at the balance sheet date of 31 December 2023.
The comparative period is the calendar year 2022, ending at the balance sheet
date of 31 December 2022.
On 22 December 2022, by means of a Scheme of Arrangement, the Company became
the new parent company for the Kistos Group of companies; the previous parent
company being Kistos plc (a company registered in England and Wales under the
Companies Act 2006 with registered company number 12949154). Following the
Scheme of Arrangement, shareholders in Kistos plc received the same number and
nominal value of Kistos Holdings plc ordinary shares. As the owners of the
original parent had the same absolute and relative interests in the net assets
of the original group and the new group immediately before and after the
reorganisation, these comparative period of these consolidated Financial
Statements is presented as if the Company headed the new group for all of the
comparative reporting period. The change in parent company and legal capital
of the group was reflected in the statement of changes in equity.
1.2 Going concern
Significant judgement - presumption of going concern
These Financial Statements have been prepared in accordance with the going
concern basis of accounting. The forecasts and projections made in adopting
the going concern basis take into account forecasts of commodity prices,
production rates, operating and G&A expenditure, committed and sanctioned
capital expenditure, foreign exchange rates and the timing and quantum of
future tax payments and receipts.
Based on the judgements set out below, which includes consideration of both
reasonably plausible downside scenarios, and mitigating actions management
could take, these Financial Statements have been prepared on a going concern
basis.
The Parent Company has minimal trade and its going concern assessment has been
performed as part of the Group's going concern assessment. The Group's cash
balances as at the end of April 2024 was €80 million. To assess the Group's
ability to continue as a going concern, management evaluated cash flow
forecasts for the period to June 2025 (the going concern period), by preparing
a base case forecast and considering reasonably plausible sensitivities and
mitigating actions that could be undertaken by the Group.
The base case going concern assessment assumed:
· First oil from the Jotun FPSO in the fourth quarter of 2024, in line
with the current operator forecast and timetable, resulting in a cash outflow
of $45 million on the Hybrid Bond in January 2025.
· Q10-A production in line with latest internal forecasts.
· Production from the GLA and Balder/Ringhorne in line with latest
available Operator forecasts and, in the case of the latter, taking into
account the first oil date from the Jotun FPSO as noted above.
· Committed and contracted capital expenditure only (being primarily
the Group's share of Balder Future capital expenditure) in line with currently
approved budgets and authorities for Expenditure (AFEs).
· A tax rebate of approximately €80 million is received in December
2024 in respect of Norwegian tax losses incurred in 2023.
· Obligations under Decommissioning Security Agreements (DSAs) for the
GLA fields are satisfied in full by the purchase of surety bonds during the
period covered by the going concern assessment (in respect of cover that needs
to be in place for 2025).
· Completion of the Gas Storage Acquisition on 23 April 2024, for cash
consideration of £25 million less closing working capital adjustments and
including estimated incremental costs of integration.
· Ongoing cash flows from the Gas Storage Acquisition in line with
existing budgets and conservative estimates from profits arising from gas
trading activities.
· Solidarity Contribution Tax charge and accrued interest (should it be
paid), will occur outside of the going concern period.
· Commodity prices based on forward curves prevailing at the date of
assessment (being an average of 76p/therm, €30/MWh and $83/bbl across the
going concern period).
The base case forecast indicated that the Group would be able to maintain a
sufficient amount of liquidity to meet its bond covenant requirement (being a
minimum liquidity of $10 million to be held within Kistos Energy Norway) and
day-to-day operations across the going concern period.
A key assumption within the base case is the timing of any payment under the
Solidarity Contribution Tax Charge, for which the Group holds a provision of
€47 million. A return in respect of this tax is required to be filed no
later than 31 May 2024, along with the payment of any tax due. As set out in
note 6.4, the Group believes that there is an argument that Kistos NL2 B.V. is
out of scope of this charge in which case no tax would be payable. In the
event the tax is payable, based on legal and tax advice received, the Group is
of the opinion that a cash outflow would occur outside the going concern
period, and after procedures, including re-assessments, objections, court
hearings and appeals, had been exhausted. However, as there is no precedent
for the payment, collection, or appeal of this tax, should the Dutch Tax
Authorities demand an earlier payment, or require payment prior to any appeal
being admitted, this would have a further material adverse effect on the
Group's liquidity (as illustrated in the reverse stress tests section below).
The other key assumption is the continued availability of surety bonds used to
cover obligations under Decommissioning Security Agreements (DSAs). The
obligation for the GLA assets in respect of 2024 was €81 million, which the
Group satisfied via the purchase of surety bonds at an approximate cost of
€2.5 million. The next redetermination will take place in June 2024, with
renewed surety bonds (or other arrangements, if applicable) to be put in place
by the end of 2024 will be for cover of an estimated obligation of €125
million . As part of the going concern assessment the Directors sought advice
from surety bond brokers over the Group's ability to renew surety bonds given
the combined impact of lower commodity prices, and higher tax and inflation
rates adversely impacting the calculation of the amount of security required.
If the bonds are not able to be renewed in full or part, the Group would
likely have to satisfy the obligations by lodging cash security, significantly
reducing available liquidity. Based on the advice received from the surety
bond providers, the Directors are of the view that the surety market will
continue to provide security up to the current DSA provisions and those
required in the foreseeable future.
As part of the assessment, reasonably plausible scenarios were also prepared
and analysed. These include:
· a reduction to the oil and gas price assumptions based on recent
price volatility;
· a reduction to forecast production rates based on reasonably
plausible changes to technical assumptions and sensitivities to extending the
impact of planned maintenance shut-ins;
· a delay in first oil from the Jotun FPSO to summer 2025 which would
result in lower production rates in Norway throughout the latter half of the
going concern period, an increase to capital expenditure incurred, but no cash
outflow in relation to the Hybrid Bond (as, under the bond terms outlined in
note 5.1 and 2.8.1, the Hybrid Bond will be cancelled in its entirety if the
first oil milestone is not met by 31 May 2025);
· adverse movement in foreign exchange rates, and
· a reduction to forecast cashflows generated from the Gas Storage
Acquisition.
The outcome of applying one or more of these reasonably plausible scenarios
against the base case indicated that during the fourth quarter of 2024 (prior
to receiving a tax repayment of c.€80 million in Norway) the Group could
breach its $10 million minimum liquidity covenant under the bonds issued by
Kistos Energy Norway or fail to maintain appropriate liquidity to continue to
meet day-to-day working capital requirements.
Reverse stress tests were also performed, which showed:
· A reduction in either sales volume or price assumption of
approximately 15% (compared to the base case forecast) for the remainder of
the going concern period, with all other factors held constant, would result
in the liquidity covenants similarly being breached in November 2024.
· An increase to 2024 capital expenditure in Norway of approximately
20% would give rise to a similar outcome.
· If, prior to November 2024, the estimated DSA obligations were
required to be fully covered in cash (with all other factors held constant),
the resulting shortfall could be greater than €80 million.
· If, prior to November 2024, or the Solidarity Contribution Tax was
required to be paid, including estimated interest, (with all other factors
held constant) the resulting shortfall could be greater than €20 million.
The Group has also considered mitigating actions it would take in the event
there was a cash shortfall. The Group is of the opinion that it would firstly
manage its liquidity position and avoid any breach via temporary working
capital management activities to cover the period of adverse liquidity prior
to the receipt of the material tax receivable noted above. Should any
shortfall not be managed via temporary working capital management, the main
potential sources of finance available to the Group include undertaking a tap
issue of the KENO02 bond (see note 5.2), for which $60 million (€56 million)
is available, securing another financing facility, and/or equity financing. A
tap issue of the KENO02 bond would require the consent of two-thirds of
bondholders represented at a bondholders meeting, although there is no
guarantee all, if any, of the additional bonds would be taken up by
bondholders (even if consent was granted). In respect of an equity raise,
while the Group and its Board have a strong track record in raising funds via
equity for Kistos and previous vehicles, raising equity financing is outside
of managements control.
Due to the potential for one or more of the reasonably plausible downside
scenarios occurring, along with the uncertainties around the payment of any
Solidarity Contribution Tax and the ability to secure the surety bonds to fund
the DSAs, the Group would be dependent on successfully completing a tap
issue of the KENO02 bond, securing another financing facility, and/or raising
equity, which are not guaranteed or wholly within Director's control. This
indicates a material uncertainty exists which may cast significant doubt about
the Group's and ultimate parent company's) continued ability to operate as a
going concern and therefore, the Group may be unable to realise its assets and
discharge its liabilities in the normal course of business.
These consolidated Financial Statements do not include any adjustments that
may result from the outcome of these uncertainties
1.3 Significant events and changes in the period
The financial performance and position of the group was significantly affected
by the following events and changes during the period:
· The acquisition of Mime Petroleum AS (Mime), subsequently renamed
Kistos Energy (Norway) AS (KENAS), in May 2023, resulting in additions of,
among other items, €126 million of fixed assets, €105 million of current
tax receivables, €68 million of abandonment liabilities, €39 million of
goodwill and €204 million of debt recognised at their estimated fair values
on acquisition (note 2.8).
· Impairment charges of €43 million in the UK segment following the
Benriach well drilled during the period proving to be sub-commercial and the
relinquishment of certain exploration licences (note 2.6.3).
· A goodwill impairment of €3 million relating to the UK exploration
cash-generating unit (CGU) as a result of the above.
· Redemption in full (at a premium) of the two bonds issued by the
Group's Dutch subsidiary, Kistos NL2 BV, resulting in a cash outflow of €84
million and a loss on redemption of €2 million (note 5.1.1).
· A decrease in average realised oil and gas sales prices and therefore
significantly lower revenue as compared to the prior period (note 2.1).
· An impairment charge of €13 million relating to production assets
in the Netherlands segment as a result of changes to commodity prices and a
reduction to estimated reserves (note 2.6.1).
1.4 Foreign currencies and translation
Items included in the Financial Statements of each of the Group's entities are
measured using the currency of the primary economic environment in which each
entity operates (the functional currency). Transactions in currencies other
than the functional currency are translated to the entity's functional
currency at the foreign exchange rates at the date of the transactions.
Foreign exchange gains and losses resulting from the settlement of monetary
assets and liabilities denominated in foreign currencies are recognised in the
income statement.
Significant judgement - functional currency of Kistos Energy (Norway) AS
Under IAS 21 'The Effects of Changes in Foreign Exchange Rates' management is
required to exercise judgement when determining an entity's functional
currency, which is defined as "the currency of the primary economic
environment in which the entity operates". Sales revenue and debt issued by
the entity is denominated in United States Dollars (USD), whereas operating
expenditure, capital expenditure, G&A and tax receivables are denominated
primarily in Norwegian Krone (NOK). Furthermore, day-to-day working capital
funding is provided by the Group in NOK. Having taken the factors and
requirements in IAS 21 into account, management has determined the functional
currency of Kistos Energy (Norway) AS to be NOK. If a different functional
currency was chosen, this would affect the volatility of revenue and operating
profit arising from exchange rate movements, determine which transactions
could and could not be hedged, influence the identification of embedded
currency derivatives and potentially give rise to temporary differences
impacting profit or loss.
All UK-incorporated entities in the Group, including Kistos Holdings plc, have
a functional currency of pounds Sterling (GBP). All Dutch-incorporated
entities have a functional currency of Euros (EUR). Norwegian-incorporated
entities have a functional currency of Norwegian Krone (NOK).
These Financial Statements are presented in EUR, a currency different to the
functional currency of the reporting entity (which is GBP). All amounts have
been rounded to the nearest thousand EUR, unless otherwise stated.
The results and balance sheet of all the Group entities that have a functional
currency different from the presentation currency are translated into the
presentation currency as follows:
· Assets and liabilities for each balance sheet presented are
translated at the closing rate at the date of that balance sheet.
· Income and expenses for each income statement are translated at
average exchange rates for the period.
· All resulting exchange differences are recognised in 'Other
comprehensive income'.
Goodwill and fair value adjustments arising on the acquisition of a foreign
operation are treated as assets and liabilities of the foreign operation and
translated at the closing rate.
1.5 Material accounting policies
The Group adopted Disclosure of Accounting Policies (Amendments to IAS 1 and
IFRS Practice Statement 2) from 1 January 2023. The adoption of these changes
has not had any impact on the Group's accounting policies but does impact
certain accounting policy information disclosed in its Financial Statements.
The amendments require the disclosure of 'material' rather than 'significant'
accounting policies and provide guidance as to the application of materiality
to the disclosure of accounting policies, with the aim of providing useful,
entity-specific accounting policy information. These amendments did not result
in changes to accounting policies but have impacted the accounting policy
information disclosed in this section.
Information concerning the Group's accounting policies is now disclosed in the
relevant section of the Financial Statements if one or more of the following
applies:
· There has been a change in accounting policies during the period.
· An accounting policy has been chosen from a set of alternatives under
IFRS.
· An accounting policy has been derived using the general guidance in
IAS 8 (in the absence of specific IFRS requirements).
· An accounting policy requires the application of significant
judgement or assumptions.
· The accounting requirements for a transaction or event are complex.
The group has applies its accounting policies consistently throughout the
current and prior periods. A minor reclassification has been made to the
presentation of certain line items in the Financial Statements and the notes:
· On the consolidated cash flow statement, interest income received is
now presented within Net cash flow from operating activities (previously Net
Cash flow from financing activities)
· On the consolidated balance sheet, balances relating to amounts due
to joint operators are now presented within Trade payables and accruals
(previously classified within 'Other liabilities').
1.6 New and amended accounting standards adopted by the Group
The Group has applied the following new accounting standards, amendments and
interpretations for the first time:
· IFRS 17 'Insurance Contracts'.
· Definition of Accounting Estimates (Amendments to IAS 8).
· International Tax Reform - Pillar Two Model Rules (Amendments to IAS
12).
· Deferred Tax related to Assets and Liabilities arising from a Single
Transaction (Amendments to IAS 12).
· Disclosure of Accounting Policies (Amendments to IAS 1 and IFRS
Practice Statement 2).
The group has elected to adopt the following amendments early:
· Classification of Liabilities with covenants as Current or
Non-current (Amendments to IAS 1).
International Tax Reform - Pillar Two Model Rules (Amendments to IAS 12)
provides a temporary exemption from deferred tax accounting for the top-up
taxes and apply retrospectively. In July 2023, the UK government enacted
legislation to implement the Pillar Two rules. However, as the Group is not
currently in scope of the Rules (due to it having global revenues of less than
€750 million) the retrospective application has no impact of the Group's
Financial Statements.
The adoption of changes and amendments above has not had any material impact
on the disclosure or on the amounts reported in the Financial Statements, nor
are they expected to significantly affect future periods.
1.7 New and amended accounting standards not yet adopted
A number of other new and amended accounting standards and interpretations
have been published that are not mandatory for the reporting period ended 31
December 2023, nor have they been early adopted. These standards and
interpretations are not expected to have a material impact on the consolidated
Financial Statements.
1.8 Accounting judgements and major sources of estimation uncertainty
In the application of the Group's accounting policies, the Directors are
required to make judgements, estimates and assumptions about the carrying
amounts of assets and liabilities that are not readily apparent from other
sources. The estimates and associated assumptions are based on historical
experience and other factors that are considered to be relevant. Actual
results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognised in the period in which the
estimate is revised if the revision affects only the period, or in the period
of the revision and future periods if the revision affects both current and
future periods.
The critical judgements, apart from those involving estimations (which are
dealt with separately below), that the Directors have made in the process of
applying the Group's accounting policies and that have the most significant
effects on the amounts recognised in the Financial Statements are:
· Determining the functional currency of Kistos Energy (Norway) AS
(note 1.4);
· The assessment of borrowing costs to be capitalised (note 2.4);
· The identification of impairment indicators for assets and goodwill
(note 2.6);
· The ongoing accounting treatment of the Hybrid Bond (note 5.1); and
· Uncertain tax positions (note 6.4).
The assumptions concerning the future, and other major sources of estimation
uncertainty at the balance sheet date that may have a significant risk of
causing a material adjustment to the carrying amount of assets and liabilities
within the next financial year, are:
· Estimated future cash flows from assets used as basis for impairment
testing for fixed assets and goodwill (note 2.6);
· Estimated quantity of hydrocarbon reserves and contingent resources
(section 2);
· The estimated cost for abandonment provisions (note 2.3); and
· The presumption of going concern (note 1.2).
1.9 Impact of climate change and energy transition on accounting judgements
and major sources of estimation uncertainty
The Directors have taken into account climate change and the desire by
national and international bodies to transition towards a lower carbon economy
were considered in preparing these consolidated Financial Statements. Most
immediately, the energy transition is likely to impact future gas and oil
prices which in turn may affect the recoverable amount of the Group's assets,
its ability to raise finance, income tax and royalties and operating and
capital costs. The estimate of future cash flows from assets, which includes
management's best estimate of future oil prices, is considered a key source of
estimation uncertainty.
Under current forecasts assuming the assets in their current condition, the
Group's UK and Dutch oil and gas assets are likely to be fully depreciated
within five years, during which timeframe it is expected that global demand
for gas and oil will remain robust. Accordingly, the impact of climate change
on expected useful lives of those assets is not considered to be a significant
judgement or estimate.
The Group's Norwegian assets are anticipated to have a remaining useful life
of 25-30 years, during which period the energy transition could significantly
impact supply and demand for oil and gas and therefore future commodity
prices. In order to estimate the sensitivity on this, management undertook two
additional sensitivity scenarios to demonstrate the potential impact of energy
transition and/or net zero policies on the carrying value of the Group's
assets. These scenarios were based on the International Energy Agency's "World
Energy Outlook 2023" report.
The two scenarios modelled were:
· the "Announced Pledges" scenario, which assume that governments will
meet, in full and on time, all of the climate-related commitments that they
have announced, including longer term net zero emissions targets; and
· the "Net Zero Emissions by 2050" scenario, which portrays a pathway
for the energy sector to help limit the global temperature rise to 1.5 °C
above pre-industrial levels in 2100 (with at least a 50% probability) with
limited overshoot.
In both scenarios, management's assumptions over commodity prices for 2024,
and 2025 was held at the same level as used in the impairment test undertaken
(note 2.6.2) before aligning, on a declining straight-line basis, to the
prices indicated in the table below. The estimated impact of these scenarios
is as follows:
Scenario 2030 crude oil price ($/bbl real terms) 2050 crude oil price ($/bbl real terms) Estimated impairment charge (€m)
Announced Pledges 74 60 -
Net Zero Emissions by 2050 42 25 15
In addition to oil and gas assets, climate change and energy transition could
adversely impact the future development or viability of intangible exploration
and evaluation assets. The existence of impairment triggers for such assets
under IFRS 6 is considered a critical accounting judgement (see note 2.6).
Section 2 Gas and oil operations
Critical judgements and key sources of estimation uncertainty applicable to
this section as a whole
Key source of estimation uncertainty - estimation of reserves and contingent
resources
Reserves and contingent resources are those hydrocarbons that can be
economically extracted from the Group's licence interests. The Group's
reserves and contingent resources have been estimated based on information
compiled by operators of the licence interests, other qualified persons, and
updated and refined by the Group's internal experts and external contractors.
These estimates use standard recognised evaluation techniques and include
geological and reservoir information (as updated from data obtained through
operation of a field), capital expenditure, operating costs and
decommissioning estimates. These inputs are validated where possible against
analogue reservoirs, and actual historical reservoir and production
performance.
Changes to reserves estimates may significantly impact the financial position
and performance of the Group. This could include a significant change in the
depreciation charge for fixed assets, the timing (and carrying value) of
abandonment provisions, the results of any impairment testing performed and
the recognition and carrying value of any deferred tax assets.
2.1 Revenue
Accounting policy
Revenue from contracts with customers is measured based on the transaction
price specified in a contract with the customer, being based on quoted market
prices for the gas or liquids. All revenue is measured at a point in time,
being that point at which the Group meets its promise to transfer control of a
quantity of gas or liquids to a customer. For gas, control is transferred once
the hydrocarbons pass a specified delivery point in a pipeline. For liquids
sales, control is transferred in accordance with the incoterms specified in
the contract. Adjustments to sales prices arising from settlement of
provisional pricing arrangements are recognised as a debit or credit to
revenue and not separated or treated as an embedded derivative.
Where compensation is received as part of a claim under loss of production
insurance, amounts receivable are presented within Other income and not within
Revenue. Subsequent remeasurements to compensation, favourable or adverse, are
also presented within Other income.
€'000
Year ended 31 December 2023
Netherlands Norway UK Total
Sales of liquids 1,298 40,722 14,107 56,127
Sales of natural gas 65,881 - 84,989 150,870
Total revenue from contracts with customers 67,179 40,722 99,096 206,997
Year ended 31 December 2022
Netherlands Norway UK Total
Sales of liquids - - - -
Sales of natural gas 285,053 - 126,459 411,512
Total revenue from contracts with customers 285,053 - 126,459 411,512
All Norway segment revenue in the current year was derived from a single
external customer. Revenues from transactions with another single external
customer amounted to €135 million across the UK and Netherlands segments.
In the prior period, revenues from transactions with one single external
customer in the Netherlands segment amounted to €285 million and revenues
from transactions with another single external customer in the UK segment
amounted to €126 million.
2.2 Segmental information
2.2.1 Segments and principal activities
The performance of the Group is monitored by the Executive Directors
(comprising the Executive Chairman, Chief Executive Officer and Chief
Financial Officer) on a geographical basis. For the period ended 31 December
2023 there are three (31 December 2022: two) reportable segments identified
for the Group's business:
· Netherlands: Comprising the production and sale of gas and other
hydrocarbons from the Q10-A field, and the costs associated with exploration,
appraisal and development of other Dutch licences.
· Norway: Comprising the production of oil from interests in the Balder
and Ringhorne Øst fields offshore Norway. This segment was created during the
current period, following the completion of the acquisition in May 2023 (note
2.8).
· UK: Comprising the production and sale of gas and other hydrocarbons
from the Group's interest in the GLA, and the costs associated with
exploration, appraisal and development of other licences in the UK North Sea.
The key measure of performance used by the Executive Directors to review
segment profit and loss is Adjusted EBITDA (note 2.2.2). They also receive
disaggregated information concerning revenue, income tax charge and capital
expenditure by segment on a regular basis. Information about other income
statement measures, and the quantum of total assets and liabilities by
segment, are not regularly provided to the Executive Directors. Transactions
between segments are measured on the same basis as transactions with third
parties and eliminate on consolidation.
2.2.2 Adjusted EBITDA
The Executive Directors use Adjusted EBITDA as a measure of profit or loss to
assess the performance of the operating segments. Adjusted EBITDA is a
non-IFRS measure, which management believe is a useful metric as it provides
additional useful information on performance and trends. Adjusted EBITDA is
not defined in IFRS or other accounting standards, and therefore may not be
comparable with similarly described or defined measures reported by other
companies. It is not intended to be a substitute for, or superior to, any
nearest equivalent IFRS measure.
Adjusted EBITDA excludes the effects of significant items of income and
expenditure which may have an impact on the quality of earnings such as
impairment charges, other non-cash charges such as depreciation and
share-based payment expense, transaction costs, changes in contingent
consideration relating to business acquisitions and development expenditure. A
reconciliation of Adjusted EBITDA by segment to profit before tax, the nearest
equivalent IFRS measure, is presented below.
€'000 Note Year ended Year ended 31 December 2022
31 December 2023
Netherlands Adjusted EBITDA 48,438 270,626
Norway Adjusted EBITDA 24,123 -
UK Adjusted EBITDA 52,055 112,899
Head office costs and eliminations (3,839) (3,510)
Group Adjusted EBITDA 120,777 380,015
Development expenses (1,146) (1,752)
Share-based payment expense 3.4 (159) (538)
Depreciation and amortisation 2.4, 2.5 (99,230) (83,234)
Impairments 2.6 (59,023) (44,547)
Transaction costs (2,581) (681)
Change in fair value and releases of contingent consideration 2.8.2 3,355 26,993
Operating (loss)/profit (38,007) 276,256
Net finance costs 3.5 (7,851) (22,131)
(Loss)/profit before tax (45,858) 254,125
Transaction costs in the current period include amounts relating to the
acquisition of Mime Petroleum. Transaction costs in the prior period relate to
those costs incurred on the GLA Acquisition, and certain costs relation to a
proposed combination with Serica Energy which did not proceed.
2.2.3 Other segmental and geographical disclosures
€'000 Year ended 31 December 2023 Year ended 31 December 2022
Income tax charge/(credit) by segment:
Netherlands 4,861 135,414
Norway 19,377 -
UK (33,317) 121,740
Unallocated and consolidation adjustments (12,098) (28,990)
Total (21,177) 228,164
€'000 Year ended 31 December 2023 Year ended 31 December 2022
Impairment charges by segment:
Netherlands 13,000 44,547
Norway - -
UK 46,023 -
Total 59,023 44,547
€'000 31 December 2023 31 December 2022
Non-current assets (other than financial instruments and deferred tax assets)
by geographical region:
Netherlands 96,728 136,735
Norway 252,690 -
UK 143,014 200,052
Total 492,432 336,787
Revenue by segment is presented in note 2.1. The amount of inter-segment
revenue was not material.
2.3 Abandonment provision
Source of estimation uncertainty - estimate of abandonment provisions
Decommissioning costs are uncertain and cost estimates can vary in response to
many factors, including changes to the relevant legal requirements, the
expected cessation of production date of the related asset, the emergence of
new technology or experiences at other assets. The expected timing, work
scope, amount of expenditure and risk weighting may also change. Therefore,
significant estimates and assumptions are made in determining the abandonment
provision balance. The estimated decommissioning costs, and inflation and
discount rates applied to derive the amounts recognised on the balance sheet,
are reviewed at least annually, and the results of this review are then
assessed alongside estimates from operators (where the Group is a
non-operating partner in an arrangement).
Accounting policy
An abandonment provision for decommissioning is recognised when the related
facilities or wells are installed. A corresponding amount equivalent to the
provision is also recognised as part of the cost of the related oil and gas
asset. Where the Group acts as operator in a joint operation, only the Group's
share of abandonment liabilities is recognised on the balance sheet. The
provision recognised is the estimated cost of abandonment at the time of
undertaking the work, discounted to its net present value, and is reassessed
typically annually. Abandonment costs expected to be incurred within 12 months
of the balance sheet date (and thus classified as current liabilities) are not
discounted.
Changes in the estimated timing of abandonment or abandonment cost estimates
are dealt with prospectively by recording an adjustment to the provision, and
a corresponding adjustment to property, plant and equipment. Where the related
item of property, plant and equipment has been fully impaired, the
corresponding adjustment is recognised in profit and loss.
€'000 Abandonment provision
At 1 January 2023 126,088
Acquisitions (note 2.8) 68,273
Accretion expense 6,301
Changes in estimates to provisions 8,979
Utilisation (1,941)
Effect of change to discount rate (1,574)
Foreign exchange differences 7,088
At 31 December 2023 213,214
Of which:
Current 4,173
Non-current 209,041
Total 213,214
Abandonment provisions comprise:
· In the Netherlands, the Group's share of the estimated cost of
abandoning the producing Q10-A wells, decommissioning the associated
infrastructure, plugging and abandoning the currently suspended Q11-B well,
and removal and restoration of certain pipelines and corresponding land from
historic onshore assets;
· In Norway, plugging and abandonment of drilled wells on Ringhorne
Øst and Balder, and removal of the Balder FPU and Ringhorne platform; and
· In the UK, the Group's share of the estimated cost of plugging and
abandoning the producing and suspended Laggan, Tormore, Edradour and Glenlivet
wells, removal of the associated subsea infrastructure, and demolition of the
Shetland Gas Plant and restoration of the land upon which the plant is
constructed.
The abandonment of the Q10-A wells and associated infrastructure is expected
to take place between six and nine years from the balance sheet date, in 2025
for the Q11-B well (based on the regulatory requirement to abandon the well by
that time as, at the balance sheet date, no extension of the suspension
consent had been concluded) and within one year for the onshore pipelines and
land restoration.
The abandonment of the UK fields, producing wells and associated
infrastructure is expected to take place between five and fourteen years from
the balance sheet based on current production and commodity price forecasts
and sanctioned development plans. Certain suspended wells may be abandoned in
2025, pending regulatory clarification.
Abandonment of currently producing Norwegian infrastructure is anticipated to
be abandoned between 2030 and 2050. The utilisation of provisions in the
period relates to the onshore abandonment of the onshore Donkerbroek-Hemrik
location and certain Ringhorne Øst wells.
Abandonment provisions are initially estimated in nominal terms, based on
management's assessment of publicly available economic forecasts and
determined using inflation rates of 2.0% to 2.5% (2022: 2.5%) and discount
rates of 2.2% to 3.8% (2022: 2.5% to 3.5%). The changes in estimates to
provisions arises primarily as a result of the increased inflation rate
assumed.
The Group has in issue €81 million of surety bonds as at 31 December 2023
(2022: €27 million) to cover its obligations under Decommissioning Security
Agreements (DSAs) for the GLA fields and infrastructure. The amount of the
bonds required is re-assessed each year, changing in line with estimated
post-tax cash flows from the assets, revisions to the abandonment cost,
inflation rates, discount rates and other inputs defined in the DSAs.
The Group is obliged to deposit to Vår Energi a post-tax amount of $12.7
million (plus interest accruing at SOFR +3%), payable three months after the
date of the first oil produced from the Balder and Ringhorne fields over the
Jotun FPSO. Based on current estimates of interest rates and expected timing
of Balder first oil, the amount to be deposited is anticipated to be
approximately $16 million. This amount will be repaid to the Group upon
decommissioning of the fields.
2.4 Property, plant and equipment
Significant judgement - assessment of capitalised borrowing costs
For longer-term upstream development projects, judgement is applied in
determining when substantially all the activities necessary to prepare assets
for their intended use are complete. This judgement impacts when the Group
ceases capitalisation of borrowing costs in accordance with IAS 23 'Borrowing
costs'. Due to the nature of these projects, in particular, where the Group
does not operate the assets or fields in question, it can be difficult to
separately identify the costs attributable to developed reserves (which are
ready for their intended use) from those costs attributable to undeveloped
reserves.
The Norwegian assets, as outlined in note 2.8, were acquired in May 2023 for a
consideration of €4 million, including €204 million of borrowings acquired
as part of the acquisition. Management has judged that these fields included
in the fair value of oil and gas assets acquired had commenced production and
that substantially all activities necessary to prepare the assets for their
intended use were complete prior to the date of acquisition. As a result, no
borrowing costs have been capitalised in respect of these fields
post-acquisition. Capital expenditures incurred subsequent to the date of
acquisition have been funded through the Group's operating cash flows and
existing cash balances rather than borrowings.
Accounting policy
All field development costs are capitalised as property, plant and equipment.
Property, plant and equipment related to production activities are depreciated
typically on the unit of production method, with the exception of the Group's
interest in the Shetland Gas Plant, which is depreciated on a straight-line
basis to the estimated cessation of production date of the related gas fields.
Where a sidetrack from an original well is drilled, the costs of the original
well are estimated and written off to the income statement. The cost of
ordinary maintenance and repairs are expensed as incurred, whereas costs for
improving and upgrading production facilities are added to the acquisition
costs and depreciated together with the related asset.
All expenditure carried within each field is depreciated from the commencement
of production on a unit of production basis, which is the ratio of oil and gas
production in the period to the estimated quantities of reserves or resources
at the end of the period plus the production in the period, generally on a
field-by-field basis or by a group of fields which are reliant on common
infrastructure. For larger ongoing development projects where both production
and significant capital expenditure are ongoing, the unit of production ratio
is calculated by reference to total expected project costs and total field 2P
reserves. For other projects, where there is no currently approved FID in
place to access 2P reserves, the unit of production ratio is calculated by
reference to the net book value of assets attributable to the field(s) and
total 1P reserves. Reserves used as the basis for unit of production
depreciation may not be the same as reserves used by management for other
internal and external reporting purposes.
€'000 Oil and gas assets Other assets Total
Cost
At 1 January 2022 185,413 325 185,738
Acquisition of business (note 2.8) 189,790 - 189,790
Additions 11,286 1,416 12,702
Disposals (11,922) (58) (11,980)
Foreign exchange differences and other movements (8,435) - (8,435)
At 31 December 2022 366,132 1,683 367,815
Acquisition of business 125,739 27 125,766
Additions 101,728 427 102,155
Foreign exchange differences and other movements 14,302 25 14,327
At 31 December 2023 607,901 2,162 610,063
Accumulated depreciation and impairment
At 1 January 2022 (14,395) (116) (14,511)
Depreciation charge for the period (83,023) (211) (83,234)
Disposals 11,922 31 11,953
Impairment (note 2.6) (286) - (286)
Foreign exchange differences and other movements 734 3 737
At 31 December 2022 (85,048) (293) (85,341)
Depreciation charge for the period (98,613) (414) (99,027)
Impairment (note 2.6) (13,000) - (13,000)
Foreign exchange differences and other movements (794) - (794)
At 31 December 2023 (197,455) (707) (198,162)
Net book value at 31 December 2022 281,084 1,390 282,474
Net book value at 31 December 2023 410,446 1,455 411,901
Due to the nature of the Group's oil and gas development projects it is not
practical to ascertain the carrying amount of expenditure that is under
construction.
The 'Other' category includes office and IT equipment, including assets
(primarily office leases) held as right-of-use assets (note 5.3).
In the prior period, 'Disposals' represented the removal of fully depreciated
assets following abandonment work undertaken in the Netherlands.
2.5 Intangible assets and goodwill
Accounting policy
The Group adopts the successful efforts method of accounting for exploration
and evaluation costs. Costs incurred before a licence is awarded or obtained
are expensed in the period. All licence acquisition, exploration and
evaluation costs and directly attributable G&A costs are subsequently
capitalised by well, field or exploration area, as appropriate. These costs
are written off as exploration costs in the income statement unless commercial
reserves have been established or the determination process has not been
completed and there are no indications of impairment.
Specific indicators that would result in an immediate impairment include
relinquishment of a licence and a sub-commercial drilling result. In such
circumstances, subsequent expenditure on those licences is also recognised as
an impairment in the income statement.
€'000 Goodwill Exploration and evaluation assets Other intangible assets Total
Cost
At 1 January 2022 7,000 158,573 - 165,573
Acquisition of business (note 2.8) 10,913 32,923 - 43,836
Additions - 8,660 - 8,660
Other - 245 - 245
At 31 December 2022 17,913 200,401 - 218,314
Acquisition of business (note 2.8) 39,029 7,167 342 46,538
Additions - 21,364 322 21,686
Foreign exchange differences 2,665 1,182 19 3,866
At 31 December 2023 59,607 230,114 683 290,404
Accumulated amortisation and impairment and impairments
At 1 January 2022 (7,000) (112,802) - (119,802)
Impairment (note 2.6) - (44,261) - (44,261)
At 31 December 2022 (7,000) (157,063) - (164,063)
Amortisation for the period - - (203) (203)
Impairment (note 2.6) (3,480) (42,543) - (46,023)
Foreign exchange differences 27 331 (4) 354
At 31 December 2023 (10,453) (199,275) (207) (209,935)
Net book value at 31 December 2022 10,913 43,338 - 54,251
Net book value at 31 December 2023 49,154 30,839 476 80,469
Exploration and evaluation assets at 31 December 2023 include the 2C
contingent resources comprising the Glendronach development in the UK, the
Orion oil prospect on the Q10-A licence and the King/Prince prospects in
Norway. The Group's interests in oil and gas licences are outlined in note
2.7.
2.6 Impairment of assets and goodwill
Critical judgement - identification of impairment indicators
Under IAS 36 the Group is required to consider if there are any indicators of
impairment for property, plant and equipment. The judgement as to whether
there are any indicators of impairment takes into consideration a number of
internal and external factors, including changes in estimated reserves,
significant adverse changes to production versus previous estimates made by
management, changes in estimated future oil and gas prices, changes in
estimated future capital and operating expenditure to develop and produce
commercial reserves, and adverse changes in applicable tax regimes. Where
indicators are present and an impairment test is required, the calculation of
the recoverable amount requires estimation of its value in use (VIU) and/or
fair value less costs of disposal (FVLCOD), using discounted cash flow models
or other approaches. These assessments are performed on a cash-generating unit
(CGU) basis, unless a lower level is deemed appropriate.
The judgement as to whether there are any indicators of impairment for
intangible exploration assets is made by reference to, among other factors,
the indicators outlined in IFRS 6, including the lack of planned or budgeted
substantive expenditure on a licence, a lack of commercially viable reserves
discovered, and other factors that indicate that the carrying amount of the
intangible asset is unlikely to be recovered in full from successful
development or by sale.
Key source of estimation uncertainty - estimated future cash flows used in
impairment testing
In performing impairment tests, management uses discounted cash flow
projections to estimate the fair value less costs of disposal of an asset's or
CGU's recoverable amount. These forecasts include estimates of future
production rates of gas and oil products, commodity prices and operating
costs, and are thus subject to significant risk and uncertainty. Changes to
external factors and internal developments and plans can significantly impact
these projections, which could lead to additional impairments or reversals in
future periods. Where applicable, a sensitivity analysis to the key estimates
and assumptions is outlined below.
2.6.1 Netherlands segment impairments
The reduction in European gas prices, in conjunction with a downwards revision
of reserves estimated to be in place at the Q10-A field, were considered by
management to be impairment triggers for the Netherlands Production CGU. The
CGU contains six producing wells at the Q10-A gas field, the Q10-A platform
and associated infrastructure.
The recoverable amount was determined on a fair value less costs of disposal
basis, using a discounted cash flow approach in line with how market
participants would value the asset (and corresponding to how the Group would
value similar assets), with the estimate therefore being classified as Level 3
in the fair value hierarchy due to a number of unobservable inputs used in the
estimate.
The key assumptions used in the valuation were as follows:
· TTF gas prices of €43/MWh in 2024, €42/MWh in 2025 and €36/MWh
in 2026 based on independent forecasts and estimates
· Gas production forecasts based on internal reservoir modelling until
cessation of production in 2028 at which point the economic limit is reached.
· Operating expenditure based on forecasts and information provided by
the operator of the P15-D platform, comprising the main component of operating
costs
· A nominal post-tax discount rate of 8%
Costs of disposal were considered to be immaterial for the purposes of the
impairment test. The recoverable amount of the CGU was estimated to be €50
million, giving rise to an impairment charge of €13 million recognised
against oil and gas assets.
In the prior period, impairment charges of €45 million were recognised in
the Netherlands segment primarily on exploration intangible assets, following,
among other factors, the introduction of additional taxes by the Dutch tax
authorities meaning there was no longer sufficient certainty over whether
their carrying values could be recovered from future development. Included
within these impairments was €7.5 million relating to the M10/11 licence
which, at the previous balance sheet date, was not held by the Group as it was
in the process of appealing its non-renewal by the Dutch authorities. The
licence was re-awarded to the Group in July 2023. As evaluation, permitting
and stakeholder engagement is still underway, it is not considered that there
is sufficient certainty that its previous carrying value will be recovered in
full and therefore no impairment reversal has been recognised.
The cumulative impairments recognised in the Netherlands segment since the
acquisition of Tulip Oil in 2021 are €179 million.
2.6.2 Norway segment impairment test
The Norway production CGU, comprising the Group's working interests in the
Balder and Ringhorne Øst fields and share of the Jotun FPSO is required to be
tested for impairment because the goodwill allocated to it (being €39
million) was acquired in a business combination during the current reporting
period.
The recoverable amount was determined on a fair value less costs of disposal
basis, using a discounted cash flow approach in line with how market
participants would value the asset (and corresponding to how the Group would
value similar assets), with the estimate therefore being classified as Level 3
in the fair value hierarchy due to a number of unobservable inputs used in the
estimate. Costs of disposal were considered to be immaterial for the purposes
of the impairment test.
The key assumptions used in the valuation were as follows:
· Production from the Balder and Ringhorne Øst continues until the end
of field life at the end of the 2040s (with decommissioning occurring in the
2050s), beyond the current licence period which expires in 2030 on the basis
that the Plan for Development and Operation (PDO) for Balder Future (which was
approved by Norwegian Ministry of Energy in 2020) extends beyond this date.
Due the nature of oil and gas production, is it not appropriate to extrapolate
cash flows using a terminal value approach.
· Nominal oil prices of $84/bbl in 2024, $80/bbl in 2025, $76/bbl in
2026 rising to $81/bbl in 2030 and increasing by 2% per annum thereafter.
· USD/NOK exchange rate of 10.5, falling to 9.5 longer term.
· A nominal post-tax discount rate of 9% reflecting the specific risks
relating to the segment and geographical region.
· Cost and production estimates reflecting the Operator's view of the
field and development project as at 31 December 2023, as reflected in the 2024
Work Programme and Budget (which was approved by both Kistos and Vår Energi)
and the Operator's longer-term Revised National Budget (RNB) submission. The
2024 budget approved assumes first oil from the Jotun FPSO in 2024.
The assumptions and values used are consistent with external sources of
information (for example, publicly available commodity price forecasts) and
budgets and assessments provided by the Operator of the assets.
The results of the impairment test were that the recoverable amount exceeded
the carrying amount by €29 million and therefore no impairment charge was
necessary.
Sensitivity analysis undertaken indicates that the following reasonably
possible changes to certain key assumptions (after incorporating any
consequential effects of that change on the other variables) would cause the
recoverable amount to be equal to the carrying amount:
· A reduction in the commodity price curves used by 13%
· An increase of the discount rate to 17%
· A reduction of estimated production rates across the life of fields
by 13%
· A reduction in the longer term USD/NOK exchange rate to 7.2
The sensitivity analysis undertaken indicated that a delay of first oil from
the Jotun FPSO to 2025 is not anticipated to cause the recoverable amount to
be lower than the carrying amount.
2.6.3 UK segment impairment test
The UK Production CGU, comprising the Group's working interest in the
producing Laggan, Tormore, Edradour and Glenlivet fields and the Shetland Gas
Plant, is required to be tested for impairment annually as goodwill allocated
to the CGU (being €7 million) was acquired in a business combination.
The recoverable amount was determined on a fair value less costs of disposal
basis, using a discounted cash flow approach in line with how market
participants would value the asset (and corresponding to how the Group would
value similar assets), with the estimate therefore being classified as Level 3
in the fair value hierarchy due to a number of unobservable inputs used in the
estimate. Costs of disposal were considered to be immaterial for the purposes
of the impairment test.
The key assumptions used in the valuation were as follows:
· NBP gas prices of 100p/therm in 2024, 101p/therm in 2025 and
82p/therm in 2026 and 2027 based on independent forecasts and estimates
prevailing at the balance sheet date;
· Costs and production estimates forecast by the asset operator, with
the expected natural decline consistent with past performance, extending to
the estimated cessation of production date in 2027 at which point a technical
production limit is reached. Due the nature of oil and gas production, it is
not appropriate to extrapolate cash flows using a terminal value approach.
· A nominal post-tax discount rate of 9% reflecting the specific risks
relating to the segment and geographical region.
The assumptions and values used are consistent with external sources of
information (for example, publicly available commodity price forecasts) and
budgets and assessments provided by the Operator of the assets.
The results of the impairment test were that the recoverable amount exceeded
the carrying amount by €2 million and therefore no impairment charge was
necessary. It is estimated that a change to the following key assumptions
would result in the recoverable amount being equal to the carrying amount:
· A reduction to the forward gas curve of approximately 4%
· A reduction to projected production rate of approximately 4%
· Use of a nominal post-tax discount rate of 13.5%
Within the UK segment Exploration CGU, the following impairments were
recognised in the current period:
· €33 million relating to the Benriach licence, following the
exploration well drilled during the period proving to be sub-commercial.
· €10 million relating to the Roseisle and Cardhu licences following
the joint venture partners electing to relinquish the licences with effect
from 1 December 2023.
· €3 million of goodwill associated with the Exploration CGU as a
result of the licence impairments above.
2.7 Joint arrangements and licence interests
Accounting policy
The Group is engaged in oil and gas exploration, development and production
through unincorporated joint arrangements; these are classified as joint
operations in accordance with IFRS 11. Where the Group is a non-operated
partner, it accounts for its proportionate net share of the assets,
liabilities, revenue and expenses of these joint operations, with amounts
billed by operators to the Group also recognised within trade payables. Where
the Group acts as operator to the joint operation, the net amount of the
liabilities is presented on the Group's balance sheet, with amounts billed to
the partners in respect of recovery of costs paid on behalf of the joint
operation recognised within receivables.
The Group has the following interests in joint arrangements at the balance
sheet date that management has assessed as being joint operations.
The operator of the licences held by Kistos Energy Limited is TotalEnergies
E&P UK Limited. The operator of the licences held by Kistos Energy
(Norway) AS is Vår Energi ASA.
Field or licence Country Licence holder Licence type Status Interest at 31 December 2023
M10a & M11(1) Netherlands Kistos NL1 B.V. Exploration Operated 60%
Donkerbroek Netherlands Kistos NL1 B.V. Production Operated 60%
Donkerbroek-West Netherlands Kistos NL1 B.V. Production Operated 60%
Akkrum-11 Netherlands Kistos NL1 B.V. Production Operated 60%
Q07 Netherlands Kistos NL2 B.V. Production Operated 60%
Q08 Netherlands Kistos NL2 B.V. Exploration Operated 60%
Q10-A Netherlands Kistos NL2 B.V. Production Operated 60%
Q10-B Netherlands Kistos NL2 B.V. Exploration Operated 60%
Q11 Netherlands Kistos NL2 B.V. Exploration Operated 60%
P12b(2) Netherlands Kistos NL2 B.V. Exploration Operated 60%
Q13b(2) Netherlands Kistos NL2 B.V. Exploration Operated 60%
Q14(2) Netherlands Kistos NL2 B.V. Exploration Operated 60%
P911, P1159, P1195, P1453(3) and P1678 UK Kistos Energy Limited Production Non-operated 20%
(Laggan, Tormore, Edradour, Glendonrach and Glenlivet)
P2411 and P1453(2) (Benriach) UK Kistos Energy Limited Exploration Non-operated 25%
PL001 Norway Kistos Energy (Norway) AS Production Non-operated 10%
PL027(4) Norway Kistos Energy (Norway) AS Production Non-operated 10%(4)
PL027C Norway Kistos Energy (Norway) AS Production Non-operated 10%
PL027HS Norway Kistos Energy (Norway) AS Production Non-operated 10%
PL028 Norway Kistos Energy (Norway) AS Production Non-operated 10%
PL028S Norway Kistos Energy (Norway) AS Production Non-operated 10%
(1) Following successful appeal against non-renewal (decision received in July
2023), the licence was re-awarded to Kistos retroactively from 30 June 2022.
(2) Awarded during the current period.
(3) Licence P1453 is split into the portion including and excluding the
Benriach area.
(4) Licence PL027 comprises Balder and Ringhorne Øst fields. Kistos' share of
the Ringhorne Øst unit is 7.4%.
2.8 Business combinations
Accounting policy
The Group accounts for business combinations using the acquisition method when
the acquired set of activities and assets meets the definition of a business
and control is transferred to the Group.
Any contingent consideration is measured at fair value at the date of
acquisition, and discounted to present value if the consideration is expected
to be settled more than 12 months from the balance sheet date. If an
obligation to pay contingent consideration meets the definition of equity it
is not remeasured, and any subsequent settlement is accounted for within
equity. (The existence of a contingent settlement provision in an equity
instrument issued as consideration for a business combination is not
considered to preclude the fixed-for-fixed criteria of IAS 32.) Otherwise,
contingent consideration is remeasured at fair value at each reporting date
and subsequent changes in the fair value are recognised in profit or loss
presented in a separate line on the face of the income statement.
On 23 May 2023, the Group completed the acquisition of the entire share
capital of, and voting interests in, Mime Petroleum AS (Mime) from Mime
Petroleum S.a.r.l., a company incorporated and operating in Norway (the 'Mime
Acquisition'). The primary purposes of the acquisition were to gain entry into
oil and gas activities on the Norwegian Continental Shelf (NCS) and to
increase and diversify the Group's hydrocarbon production, reserves and
contingent resources.
The acquisition consideration, management's assessment of the fair value of
net assets acquired, and subsequent goodwill arising are as follows:
€'000 At acquisition date
Consideration:
Cash(1) -
Fair value of warrants issued 3,672
Total consideration 3,672
Net assets acquired:
Property, plant and equipment 125,766
Intangible assets 7,509
Trade and other payables and accruals (23,456)
Other net working capital 4,075
Inventory 14,052
Tax receivable 105,052
Cash and cash equivalents 7,284
Bond debt (203,671)
Abandonment provisions (68,273)
Deferred tax liabilities (3,695)
Goodwill 39,029
Total net assets acquired 3,672
(1) The cash consideration payable was $1.
Transaction costs of €3 million were incurred, recognised within General and
administrative expenses within the income statement, and within operating
cashflows in the cash flow statement. The fair value of receivables acquired
(included within 'Net working capital') was estimated to be equal to the gross
contractual amounts receivable.
As part of the consideration, 5.5 million warrants over shares in Kistos
Holdings plc were issued to the vendor with an exercise price of 385p. 3.6
million of these warrants can be exercised until 18 April 2028, and 1.9
million can be exercised only between 30 June 2025 and 18 April 2028, but are
subject to cancellation as described below. The fair value of warrants was
estimated using a Black Scholes model and the Group's share price at the
acquisition date, adjusted for the estimated probability of issuance; and are
recognised within Other equity on the balance sheet.
As part of the completion of the transaction, the terms of the acquiree's
bonds were amended. A summary of the bonds acquired is disclosed in note 5.1.
Goodwill arises primarily from the requirements to recognise deferred tax on
the difference between the fair value and the tax base of the assets acquired.
This fair value adjustment is not tax deductible and therefore results in a
net deferred tax liability and corresponding entry to goodwill. The goodwill
itself is not deductible for tax purposes.
The Mime Acquisition contributed €41 million of revenue and a loss after tax
of €9 million for the period from acquisition date until 31 December 2023.
If the acquisition had completed on 1 January 2023, consolidated revenue for
the Group would have been €223 million and the consolidated loss after tax
is estimated to have been €57 million. The latter has been estimated as if
the fair value adjustments to fixed assets recognised at the acquisition date
had occurred at the beginning of the reporting period, but no changes to the
timing or nature of debt restructurings that occurred in the pro forma period.
The impact to the non-IFRS measure Adjusted EBITDA as if the acquisition had
completed on 1 January 2023 is disclosed in Appendix B1.
2.8.1 Acquisition in prior period
On 10 July 2022, the Group completed the acquisition of a 20% working interest
in the P911, P1159, P1195, P1453 and P1678 licences, producing gas fields and
associated infrastructure alongside various interests in certain other
exploration licences, including a 25% interest in the Benriach prospect in
licence P2411, from TotalEnergies E&P UK Limited; all comprising working
interests in unincorporated joint operations (together, the GLA Acquisition).
The headline consideration was $125 million based on an effective economic
date of 1 January 2022, with the final firm consideration payment being
reduced from $125 million by the post-tax cashflows generated from the assets
between the effective economic date and the completion date (and other
adjustments). The primary reasons for the acquisition were to diversify the
Group's production base by gaining exposure to the UK North Sea and potential
exploration upside.
The acquisition consideration, management's assessment of the net assets
acquired, and subsequent goodwill arising were as follows:
€'000 At acquisition
Consideration:
Cash 40,047
Contingent consideration 38,029
Total consideration 78,076
Net assets acquired:
Property, plant and equipment 189,790
Exploration and evaluation assets 32,923
Investment in associates 61
Net working capital (3,826)
Abandonment provisions (115,004)
Net deferred tax liability (36,781)
Goodwill 10,913
Total net assets acquired 78,076
Goodwill arose primarily from the requirements to recognise deferred tax on
the difference between the fair value and the tax base of the assets acquired.
This fair value uplift is not tax deductible and therefore results in a net
deferred tax liability and corresponding entry to goodwill.
The contingent consideration comprised two elements:
· Up to a maximum of $40 million (€39.3 million) payable based on a
formula including GLA gas production and average quoted gas prices through
2022. The fair value of this contingent consideration was assessed to be
€34.9 million at the acquisition date. The actual amount of the contingent
consideration was €16.2 million, which was settled in cash in March 2023.
· Upon the successful development of the Benriach area, consideration
of $0.25 per MMBtu of the approved net 2P reserves following first gas. The
fair value of this contingent consideration was assessed by management to be
€3.1 million on acquisition. Following the exploration well drilled on
Benriach during the year proving to be sub-commercial, the full amount of this
contingent consideration was derecognised (€3.4 million at the point of
derecognition) and a corresponding gain recognised in the income statement.
2.8.2 Movement in contingent consideration payable
The movement of contingent consideration balances is as follows:
€'000 GLA acquisition Tulip Oil acquisition
At 1 January 2022 - 15,000
Recognised on acquisition 38,029 -
Contingent consideration paid in cash - (7,500)
Gain recognised following change in fair value (19,493) -
Accretion expense 153 -
Gain on derecognition - (7,500)
Foreign exchange differences 375 -
At 31 December 2022 19,064 -
Contingent consideration paid in cash (16,219) -
Gain on derecognition (3,355) -
Foreign exchange differences 510 -
At 31 December 2023 - -
No contingent consideration was recognised as a result of the Mime
Acquisition; however, the terms of the Hybrid Bond acquired contain
provisions that are, in substance, render it as highly analogous to contingent
consideration (see the significant judgement in note 5.1).
2.9 Commitments
The Group had outstanding contractual capital commitments at the reporting
dates as follows:
€'000 31 December 2023 31 December 2022
Contractual commitments to acquire property, plant and equipment 91,430 2,553
Contractual commitments on intangible assets (including commitments on 93 27,483
exploration assets)
Total 91,523 30,036
Section 3 Income statement
3.1 Earnings per share
Year ended 31 December 2023 Year ended 31 December 2022
Consolidated (loss)/profit for the period attributable to shareholders of the (24,681) 25,961
Group (€'000)
Weighted average number of shares used in calculating basic earnings per share 82,863,743 82,863,743
Potential dilutive effect of:
Employee share options(1) - 135,989
Warrants(2) - -
Weighted average number of ordinary shares and potential ordinary shares used 82,863,743 82,999,732
in calculating diluted earnings per share
Basic earnings per share (€) (0.30) 0.31
Diluted earnings per share (€) (0.30) 0.31
1 Employee share options are not dilutive for the current period as the
average share price during the period did not exceed the exercise price of the
options.
2 The warrants issued during the period as part consideration for the Mime
Acquisition (note 2.8) are not dilutive as the average share price from the
issue date of 23 May 2023 to the period end was below the exercise price.
3.2 General and administrative expenses
€'000 Year ended 31 December 2023 Year ended 31 December 2022
Salary and related expenditure 9,179 6,598
Non-salary expenditure 4,778 3,048
Recovery and capitalisation of costs (1,960) (220)
Total general and administrative expenses 11,997 9,426
3.3 Employee benefit expenses
€'000 Year ended 31 December 2023 Year ended 31 December 2022
Wages and salaries 7,844 6,286
Social security and pension costs 1,300 910
Equity-settled share-based payment expense (note 3.4) 159 538
Total employee benefit expenses 9,303 7,734
At 31 December 2023, the Group employed 33 people (31 December 2022: 24).
The monthly average number of full-time equivalent employees in the Group,
excluding non-Executive Directors, is as follows:
Year ended 31 December 2023 Year ended 31 December 2022
Technical 12 14
Finance, legal and support 10 7
Management 7 3
Total 29 24
3.4 Share-based payment arrangements
The Group has in place share option schemes for certain employees across its
subsidiaries that are accounted for as equity-settled share-based payments.
The total charge in respect of share-based payments was €0.2 million (2022:
€0.5 million).
The total number of share options outstanding at 31 December 2023 was 166,560
(31 December 2022: 191,068), which have exercise prices in the range of
273-441p/share (31 December 2022: 273-343p/share). The closing share price of
the Group's Ordinary Shares at 31 December 2023 was 165p.
No share options are in place for Directors.
3.5 Interest and other net finance costs
€'000 Year ended 31 December 2023 Year ended 31 December 2022
Bank interest income 7,446 267
Interest on tax receivables 1,824 -
Other interest income 26 -
Total interest income 9,296 267
Bond interest (23,620) (10,543)
Other interest - (268)
Interest on tax (4,238) -
Surety bond interest (913) (472)
Total interest expenses (28,771) (11,283)
Accretion expense on abandonment provisions and other liabilities (note 2.3 (6,301) (2,028)
and 2.8.2)
Accretion expense on lease liabilities (101) (42)
Amortisation of bond costs (note 5.1) (1,024) (1,062)
Remeasurement loss on Hybrid Bond (note 5.1) (3,169) -
Loss on bond repurchases (note 5.1.1) (2,404) (6,414)
Net foreign exchange gains on bond debt 24,218 -
Net other foreign exchange gains/(losses) 405 (1,569)
Total other net finance income/(costs) 11,624 (11,115)
Total net finance costs (7,851) (22,131)
Section 4 Working capital
4.1 Cash and cash equivalents
Cash and cash equivalents consist of bank accounts and restricted cash
balances. Restricted funds relate to a bank guarantee for the office leases
and employee withholding taxes in Norway. Under the terms of its bonds, the
Group is required to maintain a minimum liquidity balance of $10 million until
first oil from the Jotun FPSO (note 5.1).
€'000 31 December 2023 31 December 2022
Bank accounts 194,431 211,958
Restricted funds 167 22
Cash and cash equivalents 194,598 211,980
4.2 Trade and other receivables
€'000 31 December 2023 31 December 2022
Trade receivables 8,287 -
Accrued income 8,892 47,962
Receivables due from joint operation partner 591 3,198
Other receivables and cash overcalls 1,807 1,594
Prepayments 6,262 679
VAT receivable 624 1,129
Total trade and other receivables 26,463 54,562
Accrued income represents amounts due in respect of gas sales that had not
been invoiced at the balance sheet date. All accrued income amounts had been
invoiced and collected in full within one month of the corresponding reporting
date. Information about the Company's exposure to credit risk and impairment
losses for other short-term receivables is included in note 4.6.
4.3 Trade payables and accruals
€'000 31 December 2023 31 December 2022
Trade payables 6,179 7,271
Payables to joint operators 2,612 1,945
Accruals 31,465 12,101
Total trade payables and accruals 40,256 21,317
Trade payables are unsecured and generally paid within 30 days. Accrued
expenses are also unsecured and represents estimates of expenses incurred but
where no invoice has yet been received. The carrying value of trade payables
and other accrued expenses are considered to be fair value given their
short-term nature. A reclassification to the prior period has been made in
order to present 'Payables to joint operators' within 'Trade payables and
accruals' (previously classified within 'Other liabilities').
4.4 Other liabilities
€'000 31 December 2023 31 December 2022
Bond interest payable 971 831
Salary and other payroll-related liabilities 981 202
Contingent consideration (note 2.8.2) - 15,796
Lease liabilities 295 282
VAT payable 621 -
Overlift 1,673 -
Other 1,086 -
Other liabilities - current 5,627 17,111
Contingent consideration - 3,268
Lease liabilities 613 929
Other liabilities - non-current 613 4,197
4.5 Inventory
Accounting policy
Liquids inventory (comprising crude oil and natural gas liquids) is held at
the lower of cost and net realisable value. The cost of liquids inventory is
the cost of production, including direct labour and materials, depreciation
and a portion of operating costs and other overheads allocated based on the
ratio of liquids to gas production, determined on a weighted average cost
basis. Net realisable value of liquids inventory is based on the market price
of equivalent liquids at the balance sheet date, adjusted if the sale of
inventories after that date gives additional evidence about its net realisable
value. The cost of liquids inventory is expensed in the period in which the
related revenue is recognised.
For spares and supplies inventories cost is determined on a specific
identification basis, including the cost of direct materials and (where
applicable) direct labour and a proportion of overhead expenses. Items are
classified as spares and supplies inventory where they are either standard
parts, easily resalable or available for use on non-specific campaigns, and
within property, plant and equipment or intangible exploration and evaluation
assets where they are specialised parts intended for specific projects. Write
downs to estimated net realisable value are made for slow moving, damaged or
obsolete items, typically based on the ageing of stock.
€'000 31 December 2023 31 December 2022
Spares and supplies 11,791 3,896
Crude oil and natural gas liquids 8,682 5,792
Total inventory 20,473 9,688
The amount of inventory recognised as an expense in the current period was
€9.6 million (2022: nil). The movement in inventory net realisable value
provisions amounted to a charge of €1.3 million (2022: €0.8 million).
4.6 Financial instruments and financial risk management
Accounting policy
Where a financial instrument, such as the Hybrid Bond, contains both a
compound instrument and contingent settlement provisions, the entire
instrument is measured as a financial liability and not separated.
Gains or losses arising from changes to the remeasurement of the Hybrid Bond
are recognised within 'Other net finance costs' in the income statement.
4.6.1 Financial risk management objectives
The Group is exposed to a variety of risks including commodity price risk,
interest rate risk, credit risk, foreign currency risk and liquidity risk. The
use of derivative financial instruments is governed by the Group's policies
approved by the Kistos Board. Compliance with policies and exposure limits is
monitored and reviewed internally on a regular basis. The Group does not enter
into or trade financial instruments, including derivatives, for
speculative purposes.
4.6.2 Financial assets and liabilities carried at fair value
At 31 December 2023, there were no financial assets or liabilities carried at
fair value.
At 31 December 2022, the Group held one financial liability carried at fair
value, being €19 million in respect of contingent consideration for the GLA
Acquisition and classified as Level 3 in the fair value hierarchy. These
contingent consideration balances were settled or released in full in the
current year (note 2.8.2). There were no financial assets carried at fair
value at 31 December 2022.
4.6.3 Risk management framework
The Kistos Board has overall responsibility for the establishment and
oversight of the Group's risk management framework. The Kistos Board is
responsible for developing and monitoring the Group's risk management
policies.
The Group's risk management policies are established to identify and analyse
the risks faced by the Group, to set appropriate risk limits and controls but
also to monitor risks and adherence to limits. Risk management policies and
systems are reviewed when needed to reflect changes in market conditions and
the Group's activities. The Group aims to develop a disciplined and
constructive control environment in which all employees understand their roles
and obligations.
The Audit Committee oversees how management monitors compliance with the
Group's risk management policies and procedures and reviews the adequacy of
the risk management framework in relation to the risks faced by the Group.
4.6.4 Market risk
Market risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in market prices.
Market risk for the Group has been assessed as comprising foreign exchange
risk, interest rate risk and other commodity price risk.
Currency risk
Currency risk is the risk that fair value or future cash flows of a financial
instrument will fluctuate because of changes in foreign exchange rates.
The Group operates within the Netherlands, UK and Norway and is therefore
exposed to foreign exchange risk. Most of the Group's exposure to currency
risk arises in Norway, where revenue receipts and bond debt are denominated in
USD, whereas operating costs, tax receivables, working capital financing and
the majority of capital expenditure is denominated in the local functional
currency of NOK. Entities within the Group undertake transactions in
currencies other than their functional currency, which gives rise to
transactional currency risk. The Group manages this risk to an extent by
holding certain amounts of cash in currencies other than the entity's
functional currency to act as an economic hedge against foreign exchange
movements; however, the Group does not currently have a formal currency risk
management policy or enter into any currency hedges.
As at 31 December 2023, 17% of the Group's cash and cash equivalents was held
in EUR (31 December 2022: 49%).
A 15% strengthening of USD relative to NOK at 31 December 2023 would have
adversely impacted equity and profit and loss by approximately €24 million,
with a corresponding 15% weakening positively impacting equity and profit and
loss would have by approximately €24 million. This analysis assumes that all
other variables, in particular interest rates, remain constant, and ignores
any impact of forecast sales and/or expenses. The exposure to other foreign
currency movements is not material.
The currency sensitivity analysis selected (USD to NOK) has changed from that
used in the prior year (GBP to EUR) as, following the Mime Acquisition, the
Group carries a material amount of bond debt denominated in a currency other
than the issuing entity's functional currency and is therefore exposed to
greater risk in respect of that currency pairing.
Interest rate risk
Interest rate risk is the risk that the fair value of future cash flows of a
financial instrument will fluctuate because of changes in market interest
rates.
The Group is exposed to interest rate movements through its cash and cash
equivalents deposits which earn interest at variable interest rates. There is
no interest rate exposure on the Group's borrowings as they carry fixed rates
of interest (note 5.1).
For the period ended 31 December 2023, it is estimated that a 1% increase in
interest rates would have increased the Group's profit after tax by
approximately €2 million, and a 1% decrease would have reduced the Group's
profit after tax by approximately €2 million. This sensitivity has been
calculated only based on the average cash balances held and estimating an
effective tax rate on interest income across the Group. The impact on equity
would be the same as the impact on profit after tax.
Other price risks - commodity price risk
Commodity risk predominantly arises from the sale of natural gas and crude oil
from the Group's interests in oil and gas licences, as the price realised from
the sale of natural gas and crude oil is determined primarily by reference to
quoted market prices on the day and/or month of delivery.
The Group has previously used derivatives to mitigate the commodity price risk
associated with its underlying oil and gas revenues. Where such transactions
are carried out, they are done based on the Company's guidelines.
In 2021, Kistos NL2 hedged a portion of monthly production from the Q10-A
field (being the hedged item) at an amount of 100,000 MWh per month at a price
of €25/MWh (being the hedged instrument) for the nine-month period from July
2021 to March 2022. The hedge was fully effective in the prior period.
As at 31 December 2023, the Group had no commodity price hedging arrangements
in place.
The Group enters into other commodity contracts (such as purchases of carbon
emission allowances, fuel and chemicals) in the normal course of business,
which are not derivatives, and are recognised at cost when the transactions
occur.
4.6.5 Credit risk
Credit risk is the risk that the Group will suffer a financial loss as a
result of another party failing to discharge an obligation and predominantly
arises from cash and other liquid investments deposited with banks and
financial institutions, receivables from the sale of natural gas and other
hydrocarbons, and receivables outstanding from its joint operation partner.
The Group has policies that cover the management of credit risk, including
review of counterparty credit limits and specific transaction approvals. The
Group's oil and gas sales are made to international oil market participants
including the oil majors, trading houses and refineries. Joint operators are
international major oil and gas market participants and entities wholly owned
by the Dutch state. Material counterparty evaluations are conducted utilising
international credit rating agency and financial assessments. Where considered
appropriate, security in the form of trade finance instruments from financial
institutions with appropriate credit ratings, such as letters of credit,
guarantees and credit insurance, are obtained to mitigate the risks.
The Group held cash and cash equivalents of €195 million as at 31 December
2023 (2022: €212 million). As at 31 December 2023, over 99% of the Group's
cash and cash equivalents (2022: over 99%) are held with bank and financial
institution counterparties which have an investment grade credit rating and as
such the Group considers that its cash and cash equivalents have low credit
risk.
The carrying values of cash and cash equivalents and trade and other
receivables (excluding prepayments) represent the Group's maximum exposure to
credit risk at year end, as the Group has not recognised an allowance for
credit losses in the current or prior period. The Group has no material
financial assets that are past due.
4.6.6 Liquidity risk
Liquidity risk is the risk that the Group will encounter difficulty in meeting
obligations associated with its financial liabilities that are settled by
delivering cash or other financial assets.
The Group manages its liquidity risk using both short- and long-term cash flow
projections, supplemented by debt financing plans and active portfolio
management. Ultimate responsibility for liquidity risk management rests with
the Kistos Board, which has established an appropriate liquidity risk
management framework covering the Group's short-, medium- and long-term
funding and liquidity management requirements.
Cash forecasts are regularly produced, and sensitivities run for different
scenarios including, but not limited to, proposed acquisitions and/or
disposals, changes in commodity prices, different production rates from the
Group's producing assets and delays to development projects. In addition to
the Group's operating cash flows, portfolio management opportunities are
reviewed to potentially enhance the financial capability and flexibility of
the Group.
The Group's financial liabilities comprise trade payables (note 4.3), other
liabilities (note 4.4) and bond debt (note 5.1). The maturity analysis of
financial liabilities is shown in note 4.7.
In addition to the amounts held on balance sheet, the Group has in issue €81
million of surety bonds as at 31 December 2023 (2022: €27 million) to cover
its obligations under Decommissioning Security Agreements (DSAs) for future
abandonment of the GLA fields and infrastructure. Should the Group be in
default under the DSAs resulting in the bond provider being required to pay
out on those bonds, the Group would be required to indemnify the providers by
paying cash to cover their liability. If the surety market were to deteriorate
such that the Group is unable to renew its bonds, then the Group would be
required to satisfy its DSA obligations by transferring an equivalent amount
of its cash into trust.
The Group is obliged to deposit to Vår Energi a post-tax amount of $12.7
million (plus interest accruing at SOFR +3%), payable three months after the
date of the first oil produced from the Balder and Ringhorne fields over the
Jotun FPSO. Based on current estimates of interest rates and expected timing
of Balder first oil, the amount to be deposited is anticipated to be
approximately $16 million. This amount will be repaid to the Group upon
decommissioning of the fields.
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(1) 1,272 3,917 295,237 - 300,426
Trade payables, accruals and other financial liabilities 42,947 - - - 42,947
Lease liabilities 92 274 735 - 1,101
At 31 December 2023 44,311 4,191 295,972 - 344,474
Bond debt - 7,379 98,319 - 105,698
Contingent consideration 15,796 - - 6,191 21,987
Trade payables, accruals and other financial liabilities 21,519 - - - 21,519
Lease liabilities 75 308 1,110 - 1,493
At 31 December 2022 37,390 7,687 99,429 6,191 150,697
Where cash flows are denominated in foreign currencies, the prevailing spot
rate at the end of the period has been used to translate into the
presentational currency.
1. Bond debt excludes the Hybrid Bond, which will have cash outflows in 2025
of either $45 million (payable within 3 months), $30 million (payable within 3
months to 1 year), $15 million (payable within 3 months to 1 year) or $nil
depending on the timing of milestones achieved from the Jotun FPSO (note 5.1).
Section 5 Capital and debt
5.1 Bond debt
The Group has in issue bond debt as follows:
31 December 2023 31 December 2022
Bond Issuer Currency Coupon rate Maturity date Face value Carrying amount Face value Carrying amount
(issued currency) €'000 (issued currency) €'000
KENO01 KENAS USD 10.25%(1) November 2027 $116,809,148 90,655 - -
KENO02 KENAS USD 9.75%(2) September 2026 $124,786,992 110,803 - -
Hybrid Bond KENAS USD n/a March 2083(3) $45,000,000 14,264 - -
€90 million bond Kistos NL2 EUR 8.75% November 2024(4) - - €21,572,000(5) 22,706
€60 million bond Kistos NL2 EUR 9.15% May 2026(4) - - €60,000,000 60,000
Total €'000 215,722 82,706
1. Interest payable wholly in kind via issuance of new bonds annually in
December.
2. Interest payable partly in cash (4.5%) quarterly and partly in kind via
issuance of new bonds (5.25%) quarterly.
3. Certain amounts of the Hybrid Bond will be cancelled for nil consideration
should milestones relating to the Jotun FPSO not be met. If the milestones
have not been met by 31 May 2025, the Hybrid Bond will be cancelled in its
entirety.
4. These bonds were redeemed in full by exercise of call options in December
2023.
5. Net of €68.4 million of bonds held in treasury.
Significant judgement - accounting treatment of Hybrid Bond
Included within the bond debt acquired is the Hybrid Bond, payment of which is
contingent on an operational milestone being met, being the offload of 500,000
barrels (gross) of Balder crude oil from the Jotun FPSO. The Hybrid Bond will
be settled in full ($45 million) if the milestone is met by 31 December 2024.
This will decline to $30 million if the milestone is met between 1 January
2025 and 28 February 2025, and to $15 million if the milestone is met between
1 March 2025 and 31 May 2025. If the milestone has not been met by 31 May
2025, the Hybrid Bond will be cancelled in its entirety and bondholders will
instead be allocated 2.4 million warrants exercisable into ordinary shares of
Kistos Holdings plc at a price of 385p each, exercisable between 30 June 2025
and 18 April 2028. Simultaneously, 1.9 million of the 5.5 million warrants
issued to the vendor as consideration for the Mime Acquisition will be
cancelled.
The Hybrid Bond is a financial liability and is measured at amortised cost. At
each measurement date, the carrying value is re-estimated based on expected
future cashflows which take into account the expectation and timing oof the
milestones being met. Any remeasurement is recorded in profit or loss within
finance costs.
The KENO01 and KENO02 bonds have minimum liquidity requirements of the issuer,
being $10 million minimum liquidity, applicable from 1 January 2024 until
first oil from the Jotun FPSO. The minimum liquidity requirement prior to 1
January 2024 was $5 million, and the issuer complied with the covenants at all
times.
The Group has call options to redeem its bonds as follows:
Bond Call price Period of call option
KENO01(1) 100% From full discharge/redemption of KENO02 until maturity
KENO02(1) 100% Anytime until maturity
Hybrid bond(1) 100% From full discharge/redemption of both KENO01 and KENO02 until maturity
1. Must be called in full, not in part.
5.1.1 Repurchase of bonds
Accounting policy
Where debt instruments issued by the Group are repurchased, the financial
liability is derecognised at the point at which cash consideration is settled,
even if the associated instruments cannot be legally cancelled. Upon
derecognition, the difference between the liability's carrying amount that has
been derecognised and the consideration paid is recognised as a gain or loss
in the within finance costs. Upon early settlement or redemption of bonds, any
unamortised bond costs are released to the income statement at the point at
which the entire instrument is extinguished rather than on a pro rata basis.
During 2023, the Group repurchased €4.9 million in nominal value of its
€90 million bonds in the open market at an average price of 102%. Although
the bonds could not be cancelled, the liability relating to the repurchased
amount was treated as being extinguished.
In December 2023, the Group exercised its call options on the €60 million
and remaining €16.8 million of the €90 million bonds; the applicable call
price being 102.5%. Due to the bonds being repurchased at a premium, a total
loss of €2 million was recognised, reconciled as follows:
€'000
Cash consideration paid for repurchase of bond principal 83,599
Carrying value of bond derecognised (81,195)
Loss on repurchase of bond 2,404
5.2 Reconciliation of liabilities arising from financing activities
€'000 Bond debt Bond interest payable Other liabilities Total
At 1 January 2022 145,074 1,854 122 147,050
Financing cash flows (71,773) (11,566) (209) (83,548)
Non-cash movements:
Interest expense and amortisation of bond costs 1,085 10,543 - 11,628
Loss on bond repurchase 6,414 - - 6,414
New leases entered into - - 1,297 1,297
At 31 December 2022 80,800 831 1,210 82,841
Financing cash flows (83,599) (11,720) (383) (95,702)
Non-cash movements:
Acquisitions (note 2.8) 203,671 7,402 - 211,073
Issue of new bonds via payment-in-kind interest 15,052 (15,052) - -
Interest expense and amortisation of bond costs 5,414 19,230 101 24,745
Loss on bond repurchase 2,404 - - 2,404
Remeasurement of Hybrid Bond 3,169 - - 3,169
Foreign exchange differences (11,189) 280 (21) (10,930)
At 31 December 2023 215,722 971 907 217,600
5.3 Leases
Lease liabilities are included within Other liabilities on the balance sheet,
and right-of-use assets are included within the Other category of Property,
plant and equipment. The carrying value of right-of-use assets at 31 December
2023 was €0.9 million (31 December 2022: €1.2 million). The depreciation
charge on right-of-use assets, cash outflow for leases and expenses relating
to low-value and short-term leases was not material in either period
presented.
In the prior period, additions of €1.3 million were made to right-of-use
assets, primarily relating to the lease of the Group's new head office in
London.
5.4 Share capital and premium
Number of shares Share capital Share premium
(€'000)
(€'000)
At 1 January 2022 82,863,743 9,627 94,181
Issue and cancellation of bonus shares - - 14,734
Capital reduction - - (50,000)
Capital reorganisation - (163) (58,915)
At 31 December 2022 82,863,743 9,464 -
At 31 December 2023 82,863,743 9,464 -
Ordinary shares have a nominal value of £0.10 per share. The Group's policy
is to manage a strong capital base so as to manage investor, creditor and
market confidence, and to sustain growth of the business. Management monitors
its return on capital. There are currently no covenants related to the equity
of the Group.
Following approval by the Group's shareholders at the Annual General Meeting
in June 2022 and subsequent sanction by the Court in October 2022, the full
balance of the merger reserve in Kistos plc was allotted to share premium by
means of a bonus share issue and cancellation. A capital reduction was then
undertaken to reduce the share premium account of Kistos plc by €50 million
with the corresponding credit to retained earnings. These transactions were
undertaken in order to increase the distributable reserves of Kistos plc, the
parent company of the consolidated group at the time.
In December 2022, the Group's shareholders and the High Court of Justice of
England and Wales sanctioned a scheme of arrangement whereby Kistos Holdings
plc, a newly incorporated entity, became the new ultimate parent company of
the Group with shareholders receiving one Kistos Holdings plc share for each
Kistos plc share held.
The share premium reserve represented amounts paid up on ordinary shares in
excess of their nominal value. Following the capital reorganisation, the share
premium account reflects that of Kistos Holdings plc, which is nil.
5.5 Other equity
Other equity comprises the Warrants reserve which has a balance of €3.7
million. This reserve arose on completion of the Mime Acquisition (note 2.8),
whereby 5.5 million warrants were issued to the vendor as part of the
consideration. The warrants allow the holder to subscribe to shares in Kistos
Holdings plc at an exercise price of £3.85 per share.
Upon issue, the warrants were measured at fair value using a Black Scholes
option pricing model, adjusted for probability of issuance, and are not
subsequently remeasured.
5.6 Other reserves
Accounting policy
Where a capital reorganisation takes place resulting in a newly incorporated
entity acquiring the existing Group, the new entity does not meet the
definition of a business and the transaction is therefore outside the scope of
IFRS 3. In such a transaction, the substance of the Group has not changed
therefore the consolidated Financial Statements of the new entity are
presented using the balances and values from the consolidated Financial
Statements from the previous entity. The net assets of the new group remain
the same as the existing group.
The movements in ordinary shares and other transactions impacting share
capital, share premium and the merger and capital reorganisation reserve are
as follows:
€'000 Merger reserve Capital reorganisation reserve Hedge reserve Translation reserve Share-based payment reserve Total
At 1 January 2022 14,734 - (5,890) 382 - 9,226
Other comprehensive income - - 5,890 (43) - 5,847
Transactions with owners:
Issue and cancellation of bonus shares (14,734) - - - - (14,734)
Capital reorganisation 140,105 (80,995) - - - 59,110
Equity-settled share-based payments - - - - 538 538
At 31 December 2022 140,105 (80,995) - 339 538 59,987
Other comprehensive income - - - 93 - 93
Transactions with owners:
Equity-settled share-based payments - - - - 159 159
At 31 December 2023 140,105 (80,995) - 432 697 60,239
The merger reserve originally represented the difference between the value of
shares in Kistos plc issued as part of the total consideration of the
acquisition of Kistos NL1 and the nominal value per share. Following the
capital reorganisation and creation of Kistos Holdings plc as the new parent
entity of the Group, the merger reserve now represents the merger reserve of
Kistos Holdings plc, being the difference between the amount at which the
investment in Kistos plc was recorded and the aggregate nominal value of the
shares in Kistos Holdings plc issued.
The capital reorganisation reserve arises only on consolidation and represents
the difference between the equity structure of Kistos Holdings plc (as the new
parent company of the Group) and the equity structure of Kistos plc (as the
parent company of the Group) following the scheme of arrangement.
The hedge reserve is used to record the effective portion of gains or losses
on derivatives qualifying as cash flow hedges. Amounts are subsequently
reclassified to the income statement when the related hedges are realised.
The translation reserve comprises foreign currency differences arising from
the translation of the Financial Statements of foreign operations.
The share-based payment reserve is used to record the grant-date fair value of
share options issued to employees of the Group. corresponding entry to the
share-based payment reserve is the charge of share-based payment expense (note
3.4).
Section 6 Tax
6.1 Tax charge or credit for the period
€'000 Year ended 31 December 2023 Year ended 31 December 2022
Current tax:
Current tax (credit)/charge for current year (21,995) 195,531
Prior period adjustments for current tax (1,327) -
Total current tax (credit)/charge (23,322) 195,531
Deferred tax:
Origination and reversal of temporary differences 5,791 (30,321)
Imposition of Energy Profits Levy in the UK - 62,954
Adjustments in respect of prior periods (3,646) -
Total deferred tax (credit)/charge (2,145) 32,633
Total tax (credit)/charge (21,177) 228,164
The income tax credit or charge for the period can be reconciled to the
accounting profit or loss as follows:
€'000 Year ended 31 December 2023 Year ended 31 December 2022
(Loss)/profit before tax (45,858) 254,125
Income tax credit/(charge) calculated at the domestic tax rate applicable to 29,494 (142,880)
each entity's activities
Investment allowances and other enhanced deductions 9,611 7,471
Income and expenditure not taxable or deductible (22,119) 21,799
Utilisation of losses - 7,021
Deferred tax not provided and losses not recognised 175 (3,406)
Impact of Energy Profits Levy in the UK - (71,573)
Solidarity Contribution Tax charge (note 6.4) - (46,935)
Adjustments in respect of prior periods 4,973 -
Other (including changes to, and differences in, tax rates) (957) 339
Tax credit/(charge) 21,177 (228,164)
Effective tax rate 46.2% 89.8%
The applicable domestic tax rates for the Group's activities are as follows:
Year ended 31 December 2023 Year ended 31 December 2022
Netherlands 50% 50%(1)
Norway 78% n/a
United Kingdom 75% 65%
United Kingdom (non-ring fence activity) 23.5% 19%
1 Excluding impact of the Solidarity Contribution Tax charge.
6.2 Deferred tax
6.2.1 Deferred tax liabilities
The movement in the deferred tax liability account is as follows:
€'000 Year ended Year ended
31 December 2023 31 December 2022
Deferred tax liability at beginning of period 118,325 57,288
Recognised on acquisition (note 2.8) 3,695 36,781
Charged to income statement 3,511 25,594
Foreign exchange differences 4,922 (1,338)
Deferred tax liability at end of period 130,453 118,325
Deferred tax liabilities primarily comprise temporary differences arising on
fixed assets.
6.2.2 Deferred tax assets
€'000 Tax losses Provisions Fixed assets and other Total
At 1 January 2022 7,015 4,168 2,313 13,496
Charged to other comprehensive income - - (5,891) (5,891)
(Charged)/credited to income statement (7,015) (697) 673 (7,039)
At 31 December 2022 - 3,471 (2,905) 566
Credited to income statement - 75 1,291 1,366
At 31 December 2023 - 3,546 (1,614) 1,932
In the prior period, deferred tax assets relating to tax losses related to
Corporate Income Tax (CIT) and State Profit Share (SPS) losses in the
Netherlands, losses which were fully utilised during the prior period.
Accumulated UK non-ring fence tax losses of €16 million have not been
recognised due to the uncertainty of where future UK non-ring fence profits
may arise from. SPS losses of €56 million in the Netherlands have not been
recognised due to the uncertainty of future profits arising in the entity
holding those losses. These losses can be carried forward indefinitely subject
to the entity continuing to hold a production licence.
6.2.3 Changes to tax rates
In June 2023, the UK Government announced further changes to the Energy
Profits Levy (EPL), introducing the Energy Security Investment Mechanism
(ESIM) whereby if average oil and gas prices are sustained below $71.40/bbl
and 54p/therm (adjusted annually by CPI) for a continuous period of six months
then legislation will be introduced to remove EPL effective from that point.
Based on management's assessment of future oil and gas prices, the ESIM is not
anticipated to be triggered and therefore deferred tax balances have been
measured on the basis of EPL applying until March 2028. In March 2024, the UK
Government announced an extension of the Energy Profits Levy until March 2029.
This extension has not yet been substantively enacted; however, given the
economic life of the Group's UK oil and gas assets in their current condition
and the status of future potential developments, this change is not
anticipated to have a material impact to the Group's deferred taxation charge.
The tax rate applicable to UK entities outside of the ring-fence increased
from 19% to 25% with effect from 1 April 2023.
6.3 Current tax
6.3.1 Current tax receivable
The Group has a current tax asset of €80 million wholly relating to tax
losses incurred in Norway. This is anticipated to be received by the Group in
December 2024, and accrues repayment interest (the current statutory rate
being 4.5%) from 1 January 2024.
6.3.2 Current tax liabilities
The Group has current tax liabilities by segment as follows:
31 December 2023 31 December 2022
Netherlands 49,919 77,627
Norway - -
United Kingdom 78,697 65,507
Total 128,616 143,134
All current tax liabilities relate to taxation of oil and gas activities and
is anticipated to be settled within one year of the balance sheet date, except
€47 million relating to the Solidarity Contribution Tax (note 6.4) in the
Netherlands, for which the timing of settlement is uncertain.
Late or underpaid tax accrues interest at a rate of 6.25% in the UK and 10% in
the Netherlands. €4 million of late payment interest was charged in the
current period (2022: nil).
6.4 Uncertain tax positions
Significant judgement - recognition of Solidarity Contribution Tax provision
In October 2022, the EU member states adopted Council Regulation (EU)
1854/2022, which required EU member states to introduce a Solidarity
Contribution Tax for companies active in the oil, gas, coal and refinery
sectors. The Dutch implementation of this solidarity contribution was
legislated by a retrospective 33% tax on 'surplus profits' realised during
2022, defined as taxable profit exceeding 120% of the average taxable profit
of the four previous financial years. Companies in scope are those realising
at least 75% of their turnover through the production of oil and natural gas,
coal mining activities, refining of petroleum or coke oven products.
The Group believes that there is an argument that Kistos NL2 B.V. is out of
scope of the regulations as, in its opinion, less than 75% of its turnover
under Dutch GAAP (the relevant measure for Dutch taxation purposes) was
derived from the production of petroleum or natural gas, coal mining,
petroleum refining, or coke oven products. Furthermore, the Group understands
the implementation of the tax, including its retrospective nature, is subject
to legal challenges by other parties and certain EU member states. However, as
there is no history or precedent for this tax being audited or collected by
the Dutch tax authorities, the Directors, having taken all facts and
circumstances into account, applied IFRIC 23, 'Uncertainty over Income Tax
Treatments' and made a provision of €47 million relating to the Solidarity
Contribution Tax within the current tax charge for the prior period. This is
the single most likely amount of the charge if it becomes payable. The Group
expects to get further certainty around this tax position in 2024. A return in
respect of the Solidarity Contribution Tax is required to be filed no later
than 31 May 2024, along with the payment of any tax due. Should the tax
authorities issue an adverse ruling against the Group, and determine that the
Group was grossly negligent or undertook wilful misconduct in submitting a nil
return, non-filing or late filing of the tax return (or did not pay an amount
indicated in the tax return) then material fines or penalties could apply.
Late payment interest would also be incurred from 31 May 2024 until the date
of final payment; the current rate of interest applicable being 10%.
Accounting policy
Where the Group takes positions in tax returns in which the applicable tax
regulation is subject to interpretation, it considers whether it is probable
that the relevant tax authority will accept that uncertain tax treatment. The
Group also considers the range of potential penalties, interest or other
charges that may arise from the late payment of taxes. The Group measures its
tax liabilities (and related penalties, interest and other charges) based on
either the most likely amount if the outcomes are binary, or the expected
value if there is a range of possible outcomes.
Section 7 Other disclosures
7.1 Related party transactions
Details of transactions between the Group and other related parties are
disclosed below.
7.1.1 Compensation of Directors and key management personnel
Key management personnel are considered to comprise the Directors of Kistos
Holdings plc.
€'000 Year ended 31 December 2023 Year ended 31 December 2022
Short-term employee benefits 3,092 2,607
Post-employment benefits 224 191
Total Directors' remuneration 3,316 2,798
Short-term employee benefits include €0.4 million of bonuses payable which
were unpaid at year end and are included within 'Other liabilities' on the
balance sheet.
In the event of a change in control of the Group, the Group is committed to
pay the Executive Chairman, CEO and CFO an amount equivalent to 100% of their
cash compensation received in the 12 months prior to a change of control being
announced.
No long-term benefits, termination benefits or share-based payment expense was
recognised in respect of the Directors. Further information regarding
Directors' remuneration is provided in the Remuneration Report. The
highest-paid Director had total remuneration for the period of €1.1 million
(2022: €0.9 million).
7.1.2 Loans to key management personnel
€'000 Year ended 31 December 2023 Year ended 31 December 2022
At start of the period 226 238
Foreign exchange movements 5 (12)
At end of the period 231 226
Loans to key management personnel are unsecured and interest free. No expense
was recognised in the current or prior period for bad and doubtful debts in
respect of loans made to related parties.
7.1.3 Other related party transactions
In the current period, the Group incurred costs of €14,000 in respect of
short-term rental of an aircraft owned by a member of key management
personnel. The amount was outstanding at the period end. The Group also sublet
a portion of its office premises to an entity wholly controlled by a member of
key management personnel for nil consideration.
In the prior period, the Group paid €56,000 in rental and other
property-related costs in respect of premises owned by a member of key
management personnel. No amounts were outstanding at the period end.
7.2 Contingencies
As part of the acquisition of Tulip Oil in 2021, the following contingent
payments could be made to the vendor should certain events occur and/or and
milestones be achieved:
· up to a maximum of €75 million relating to Vlieland Oil (now
Orion), triggered at FID and payable upon first hydrocarbons based on the net
reserves at time of sanction;
· up to a maximum of €75 million relating to M10a and M11, triggered
at FID and payable upon first gas, based on US$3/boe of sanctioned reserves;
and
· €10 million payable should Kistos take FID on the Q10-Gamma
prospect by 2025.
Based on management's current assessments and current status of the projects
and developments above, the contingent considerations above remain
unrecognised on the balance sheet.
All contingent payments relating to the GLA Acquisition have been either
settled or derecognised (note 2.8.1).
The Group is obliged to deposit to Vår Energi a post-tax amount of $12.7
million (plus interest accruing at SOFR +3%), payable three months after the
date of the first oil produced from the Balder and Ringhorne fields over the
Jotun FPSO. Based on current estimates of interest rates and expected timing
of Balder first oil, the amount to be deposited is anticipated to be
approximately $16 million. This amount will be repaid upon decommissioning of
the fields.
Contingencies arising from uncertain tax positions are disclosed in note 6.4.
7.3 Assets pledged as security
As at 31 December 2023, the carrying value of financial assets pledged as
security under the Group's bond debt (note 5.1) comprised €7 million of
trade receivables, €14 million of inventory and €15 million of cash. In
addition, the bond terms grant security over the Group's Norwegian operating
assets which had a combined carrying value in the consolidated Financial
Statements at 31 December 2023 of €211 million.
7.4 Auditor's remuneration
The Group (including its overseas subsidiaries) obtained the following
services from the company's auditors and its associates in respect of the
financial years below:
€'000 Fees for audit of the 2023 accounts Fees for audit of the 2022 accounts
Audit fees
Audit of the consolidated Financial Statements 406 223
Audit of the Financial Statements of the subsidiaries 421 421
Total audit fees 827 644
Non-audit fees
Other assurance services 6 20
Total non-audit fees 6 20
Total 833 664
7.5 Subsequent events
There are no adjusting events subsequent to the balance sheet date.
Significant non-adjusting events are outlined below.
7.5.1 Acquisition of onshore gas storage assets
On 20 February 2024, the Group agreed to acquire 100% of the issued share
capital in EDF Energy (Gas Storage) Limited, which owns and operates gas
storage facilities onshore in the United Kingdom, for cash consideration of
£25 million, less closing working capital adjustments (the 'Gas Storage
Acquisition'). The acquisition completed on 23 April 2024. There are no
contingent consideration arrangements in place. The amount of
acquisition-related costs to be incurred in the subsequent accounting periods
is not anticipated to be material.
At the time of authorisation of these Financial Statements the Group had not
completed the accounting for the Gas Storage Acquisition. Based on a
preliminary assessment, the Group anticipates that substantially all of the
fair value of the gross assets being acquired are concentrated in a group of
similar identifiable assets, and therefore the 'concentration test' provisions
of IFRS 3 'Business Combinations' can be met and the transaction will be
accounted for as an asset acquisition.
Appendix A: Glossary
2C - contingent resources
2P - proved plus probable resources
Adjusted operating costs - operating costs per the income statement less
accounting movements in inventory.
Average realised sales price - calculated as revenue divided by volumes sold
for the period.
bbl - barrel
bcf - billion cubic feet
boe - barrels of oil
equivalent
boepd - barrels of oil equivalent produced per day
CGU - Cash-generating unit
CIT - Dutch Corporate Income Tax
Company - Kistos Holdings plc
DSA - Decommissioning Security Agreement
E&P - exploration and production
EBN - Energie Beheer Nederland
EIR - Effective interest rate
FID - Final Investment Decision
FPSO - Floating production storage and offloading vessel
FPU - Floating production unit
G&A - General and administrative expenditure
Gas Storage Acquisition - the acquisition of the entire share capital of EDF
Energy (Gas Storage) Limited from EDF Energy (Thermal Generation) Limited in
April 2024
GLA - Greater Laggan Area
GLA Acquisition - the acquisition, in July 2022, of a 20%
working interest in the P911, P1159, P1195, P1453 and P1678 licences,
producing gas fields and associated infrastructure alongside various interests
in certain other exploration licences, including a 25% interest in the
Benriach prospect in licence P2411, from TotalEnergies E&P UK Limited
Group - Kistos Holdings plc and its subsidiaries
kbbl - thousand barrels
kboe - thousand barrels of oil equivalent
kboepd - thousand barrels of oil equivalent produced per day
JV - joint venture
KENAS - Kistos Energy (Norway) AS
LTI - lost time incident
MEG - monoethylene glycol
Mime - Mime Petroleum AS
Mime Acquisition -the acquisition, in May 2023, of the entire share capital
of, and voting interests in, Mime Petroleum AS (Mime) from Mime Petroleum
S.a.r.l., a company incorporated and operating in Norway
MMBtu - million British thermal units
MT - metric tonne
MWh - Megawatt hour
NCS - Norwegian Continental Shelf
nm(3) - normal cubic metre
norm price - the tax reference price set by the Petroleum Price Council for
grades of crude oil sold in Norway
NSTA - North Sea Transition Authority
PDO - Plan for Development and Operation
RNB - Norwegian Revised National Budget
ROU - right of use
scf - standard cubic feet
SGP - Shetland Gas Plant
sm(3) - standard cubic metre
Solidarity Contribution Tax - A tax levied by the Dutch Government, following
the adoption of Council Regulation (EU) 1854/2022, which required EU member
states to introduce a 'solidarity contribution' for companies active in the
oil, gas, coal and refinery sectors. The Dutch implementation of this
solidarity contribution has been legislated by a retrospective 33% tax on
'excess profit' realised during 2022, with 'excess profit' defined as that
profit exceeding 120% of the average profit of the four previous financial
years. Companies in scope are those realising at least 75% of their turnover
through the production of oil and natural gas, mining activities, refining of
petroleum or coke oven products
SPS - Dutch State Profit Share tax
SURF - Subsea, umbilicals, risers and flowlines
Appendix B Non-IFRS Measures
Management believes that certain non-IFRS measures (also referred to as
'alternative performance measures') are useful metrics as they provide
additional useful information on performance and trends. These measures are
primarily used by management for internal performance analysis, are not
defined in IFRS or other GAAPs and therefore may not be comparable with
similarly described or defined measures reported by other companies. They are
not intended to be a substitute for, or superior to, IFRS measures.
Definitions and reconciliations to the nearest equivalent IFRS measure are
presented below.
B1 Pro forma information
Pro forma information shows the impact to certain results of the Group as if
the Mime Acquisition GLA acquisition had completed on 1 January 2023, and as
if the GLA Acquisition had completed on 1 January 2022. Management believe pro
forma information is useful as it allows meaningful comparison of full year
results across periods.
€'000 Revenue Adjusted EBITDA
Period ended 31 December 2022:
As reported 411,512 380,015
Pro forma period adjustments 156,933 137,187
Pro forma 568,445 517,202
Period ended 31 December 2023:
As reported 206,997 120,777
Pro forma period adjustments 16,095 1,542
Pro forma 223,092 122,319
B2 Net debt
Net debt is a measure which management believe is useful as it provides an
indicator of the Group's overall liquidity. It is defined as cash and cash
equivalents less the face value of outstanding bond debt excluding the Hybrid
Bond which, in management's view, represents contingent consideration rather
than bond debt due to the payment triggers associated with it.
€'000 Note 31 December 2023 31 December 2022
Cash and cash equivalents 4.1 194,598 211,980
Face value of bond debt (excluding Hybrid Bond) 5.1 (218,917) (81,572)
Net (debt)/cash (24,319) 130,408
B3 Adjusted operating costs and unit opex
Adjusted operating costs are operating costs per the income statement less
accounting movements in inventory, which are primarily those operating costs
capitalised into liquids inventory as produced and expensed to the income
statement only when the related product is sold.
€'000 Year ended Year ended
31 December 2023 31 December 2022
Production costs 72,888 22,927
Accounting movements in inventory (1,048) 4,135
Adjusted operating costs 71,840 27,062
Pro forma period adjustment 10,221 19.706
Pro forma adjusted operating costs 82,061 46,768
Total production (kboe) 2,995 2,732
Pro forma period adjustment (kboe) 226 1,230
Total pro forma production (kboe) 3,221 3,962
Unit opex €24/boe €10/boe
Pro forma unit opex €25/boe €12/boe
Appendix C Conversion Factors
The conversion factors below have been used by management in the presentation
of certain disclosures in the Annual Report on a consistent basis.
37.3 scf of gas in 1 Nm3 of gas
5,561 scf of gas in 1 boe
149.2 Nm3 of gas in 1 boe
1.7 MWh of gas in 1 boe
34.12 therms of gas in 1 MWh of gas
7 MT of natural gas liquids in 1 boe
Exact conversions of volumes of gas to barrels of oil equivalent (boe), volume
of gas to energy (therms or MWh) and volumes of natural gas liquids to boe is
dependent on the calorific value of gas and exact composition of natural gas
liquids and therefore can change on a daily basis, and may be different to
those conversion factors used by other companies.
1 Source: Welligence Energy Analytics.
2 Pro forma figures for 2023 include Kistos Norway as if it had been
acquired on 1 January 2023. The acquisition completed on 23 May 2023. Pro
forma figures for 2022 include GLA as if it had been acquired on 1 January
2022. The acquisition completed on 10 July 2022. Minor adjustments have been
made to comparative pro forma information following receipt of additional
information after completion of the GLA acquisition and to align with the
Group's accounting policies and methodology as used in the 2022 Annual Report
and Accounts.
3 Non-IFRS measure (refer to definition within the glossary). Sales volumes
are converted to estimated boe using the conversion factors in Appendix C to
the Financial Statements.
4 Non-IFRS measure (refer to definition within the glossary and
reconciliation in Note 2.2.2, Appendix B2 and Appendix B3 to the Financial
Statements).
5 Non-IFRS measure (refer to definition in the glossary and Appendix B3 to
the Financial Statements).
6 Pro forma figures for 2023 include Kistos Norway as if it had been
acquired on 1 January 2023. The acquisition completed on 23 May 2023. Pro
forma figures for 2022 include GLA as if it had been acquired on 1 January
2022. Adjusted EBITDA by region is reconciled to total Adjusted EBITDA in note
2.2.2 to the Financial Statements. Pro forma information is reconciled to
actual results in Appendix B2 to the Financial Statements.
7 Operated sites and projects comprise oil and gas fields, facilities and
infrastructure where the Group has control, responsibility and accountability
over activities, safety, emissions and decisions impacting the sites. Operated
sites therefore comprise all Dutch licences, including the Q10-A platform, and
offices owned or leased by the Group.
8 Source: North Sea Transition Authority
(https://www.nstauthority.co.uk/media/5tib5x4n/nsta-gas-import-fact-sheet.pdf)
.
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