REG - Kistos Holdings PLC - Interim results
25/09/2024 07:00
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RNS Number : 5201F Kistos Holdings PLC 25 September 2024
25 September 2024
Kistos Holdings plc
("Kistos", the "Company", or the "Group")
Interim results for the six months to 30 June 2024
Kistos (LSE: KIST), the gas and oil producer pursuing opportunities across the
energy value chain, is pleased to provide its interim results for the period
to 30 June 2024.
Financial
· Net daily production averaged 8,400 boepd across Norway,
Netherlands, and the UK (H1 2023 pro-forma: 9,200 boepd)
o Stronger than expected production from the Greater Laggan Area and
expansion of the Ringhorne platform more than offset a short unplanned
shutdown of the P15 processing platform in the Netherlands
· Revenues and Adjusted EBITDA decreased compared with H1 2023,
reflecting lower commodity prices
· Cash at the end of the period of $72 million, reflecting
investment in the acquisition of EDF's gas storage assets, the settling of UK
tax liabilities, and capital expenditure in Norway's Balder Future project
· Net debt at the end of the period stood at $175 million
6 months ended 30 June 2024
H1 2024 H1 2023 Change %
(pro forma, restated)(2)
Total production rate(1) boepd 8,400 9,200 -9%
Revenue $'000 113,328 129,722 -13%
Average realised oil price $/bbl 82l 76l +8%
Average realised gas price $/boe 54 80 -33%
Adjusted EBITDA(2) $'000 48,585 73,886 -34%
1. Total production rate includes gas, oil and natural gas liquids and is
rounded to the nearest 100 barrels of oil equivalent per day. Sales and
production volumes are converted to estimated barrels of oil equivalent (boe)
using the conversion factors in the Appendix to the Interim Financial
Statements.
2. Non-IFRS measure. See note 2.2.1 to the Interim Financial Statements for
definition and reconciliation to the nearest equivalent IFRS measure.
3. Pro forma H1 2023 figures include the results from Kistos Norway as if it
had been acquired on 1 January 2023. The acquisition completed on 23 May 2023.
Comparative financial figures have been restated due to a change in
presentational currency from EUR to USD (see note 1.4 to the interim financial
statements).
Operational
· Production totalled 1.5 mmboe, with daily production averaging
8,400 boepd (H1 2023: 9,200 boepd)
· Net production from the Balder, Ringhorne and Ringhorne Øst
fields averaged 2,800 boepd (H1 2023: 2,200 boepd), reflecting both the two
new wells drilled from the Ringhorne platform, and an overall production
efficiency of 93% in H1 2024 (versus 82% in H1 2023)
· Net Q10-A (Kistos 60% and operator) production averaged 2,200
boepd (H1 2023: 3,100 boepd) due to an unplanned shutdown and planned
maintenance on the TAQA-operated P15-D platform
· Net production from Kistos' interest in the Greater Laggan Area
was above expectations at an average rate of 3,400 boepd (H1 2023: 4,300
boepd)
· Completed the acquisition of EDF's Hill Top Farm and Hole House
onshore gas storage assets in Cheshire, UK, for £25 million
o During May and June, Kistos successfully undertook the fifth and final
phase of a 'soft cycling' trial, resulting in a 24% uplift of working gas
capacity
· Full-year production guidance for 2024 is 7,500 - 8,500 boepd
Outlook
· In Norway, the Balder Future project progressed with the West
Phoenix rig completing the drilling of 14 production wells and commenced
operations on the water injection well, which was completed post-period
· First oil from the Balder Future project is now anticipated by
the end of Q2 2025, with Kistos protected from the associated cost increase by
the $45 million Hybrid Bond. This is only payable if 500,000 gross is lifted
from the Jotun FPSO before 31 May 2025
· The GLA joint venture partners are prioritising the Glendronach
development, and Kistos anticipates that a new operator of the GLA will add
additional momentum for sanctioning development projects to extract near-term
value
· During the period, the Victory field (Shell 100%) achieved
regulatory approval. This is due to come onstream via the Shetland Gas Plant
facilities in Q4 2025, extending the GLA's life and substantially reducing its
Unit operating costs of the GLA fields
· In the Netherlands, the second phase of Concept Select for the
Orion oil development was concluded successfully, and FID is awaiting clarity
on the status of projects to extend the life of existing third-party
infrastructure
· Undertaking the front-end engineering and design work to evaluate
the possibility of recommissioning the Hole House facility, which has the
potential to increase the working capacity of the onshore UK gas storage site
by over 60%
Andrew Austin, Executive Chairman of Kistos, commented:
"Maintaining high operational standards and continuing to convert the organic
opportunities within our portfolio is central to realising value for
shareholders. We have managed a season of planned and unplanned maintenance,
keeping production downtime to a minimum, and remain on track to meet our
full-year production guidance of between 7,500 - 8,500 boepd.
Alongside our partners in the GLA joint venture, we have prioritised the
Glendronach development, which will provide both production upside and further
extend the life of the Shetland Gas Plant alongside expected new third-party
throughput. Despite the delay to first production at the Balder Future project
to Q2 2025, which will have no adverse economic impact for Kistos, operational
progress has continued with the completion of production drilling activity.
We continue to pursue a pro-active M&A strategy, constantly assessing
opportunities across the value chain. In April, we completed the acquisition
of EDF's gas storage facilities in Cheshire, marking an expansion of Kistos'
midstream footprint. We have moved quickly to maximise the economic return of
the site, completing a soft cycling relaxation trial at Hill Top Farm which
confirmed the ability to increase working gas capacity by 24% from 17.8
million to 22 million therms. Importantly, this acquisition sits outside of
the upstream oil and gas tax regime, offering us greater exposure to
normalised levels of taxation on our profits.
Looking ahead, the priority remains both operational delivery and continuing
to seek out inorganic growth opportunities. We are committed to ensuring that
any transaction offers meaningful near-term value creation for shareholders,
on an acceptable risk profile. This strategy of pursuing deals not just at the
right price but on the right terms, has been validated by the mitigations put
in place around the timing of the Balder Future project, where we've protected
shareholders from additional cost whilst maintaining exposure to significant
upside potential."
Enquiries
Kistos Holdings plc via Hawthorn Advisors
Andrew Austin, Executive Chairman
Panmure Liberum (NOMAD, Joint Broker) Tel: 0207 886 2500
James Sinclair-Ford / Dougie McLeod / Mark Murphy
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 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 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. In May 2023, Kistos completed its third acquisition, acquiring the
total share capital of Mime Petroleum and its Norwegian Continental Shelf
Assets. These comprise a 10% stake in the Balder joint venture which spans the
Balder and Ringhorne oil fields, alongside a 7.4% stake in the Ringhorne East
field. In April 2024 Kistos completed its fourth acquisition, purchasing a gas
storage business from EDF Energy Storage 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' operated gas production activities offshore of the Netherlands
continue to produce with a very low carbon intensity, with estimated Scope 1
CO₂e emissions of less than 0.01 kg/boe in H1 2024.
https://www.kistosplc.com (https://www.kistosplc.com)
Kistos Holdings plc - 2024 Interim Report
Highlights
In the Netherlands, net production from the Kistos-operated Q10-A field was
2,200 barrels of oil equivalent per day (boepd) in the first half of 2024 (H1
2023: 3,100 boepd). Production was impacted by an unplanned shutdown of the
P15-D processing platform during February and the commencement of the planned
maintenance window from the 22(nd) June.
In Norway, net production in the six months to 30 June 2024 was 2,800 boepd
(H1 2023: 1,700 boepd pro forma). During the period, 2 wells were drilled from
the Ringhorne platform, which aided production rates. The West Phoenix
semi-submersible rig continued its programme to drill and complete 15 wells
relating to the Balder Future project. By the end of June, all 14 production
wells had been finished and the rig had commenced operations on the sole water
injection well, which was subsequently finished in late July.
In the UK, net production of 3,400 boepd (H1 2023: 4,300 boepd) from the
Greater Laggan Area ("GLA") fields was higher than planned due to strong
output following the unplanned shutdown during December 2023. Operations
were impacted in May by a planned 21-day turnaround at the Shetland Gas Plant
('SGP'), which was completed on schedule. Shell's Victory field development,
which received regulatory approval in January, will utilise the SGP and other
GLA infrastructure and remains on schedule for first gas by the end of 2025.
Within the GLA itself and after a further review of the relative merits of the
two near-term opportunities, the JV partners have decided to focus on the
Glendronach project rather than Edradour West. The JV also continues to
analyse the 4D seismic shot in 2023 for further infills targets in Laggan,
Tormore and Glenlivet.
In June, TotalEnergies announced the sale of its remaining 40% operated stake
in the west of Shetlands assets to Prax Upstream Limited (formerly Hurricane
Energy Plc). We are supportive of the change of operator and anticipate that
the JV will continue to work up development opportunities that have been
identified following the successful 2023 seismic acquisition campaign.
In April 2024, we completed the acquisition of EDF's UK gas storage business
which was renamed Kistos Energy Storage Limited, and comprises two facilities
- Hill Top Farm and Hole House - on a single site at Warmingham in Cheshire.
Since then, we have commenced a partnership with a third-party to trade the
available working gas on our behalf. Following the successful final phase of a
"soft cycling" trial in May, we have increased the working gas capacity of the
operational Hill Top Farm facility by c.24%. We have also now commenced a FEED
(Front-End Engineering and Design) study to investigate the potential to
re-instate the currently non-operational Hole House facility and expect to
make a Final Investment Decision in late-2024 or early-2025.
Unrestricted cash at the end of the period was $70 million (31 December 2023:
$215 million), The decrease was due to ongoing capital expenditure requirement
in Norway, the settlement of UK tax liabilities, and cash consideration paid
for the acquisition of EDF's gas storage assets. Net debt at the end of the
period was $175 million (31 December 2023: $27 million). Net debt excludes the
face value of Hybrid Bonds ($45 million), which only become payable in full or
in part if the Jotun floating production storage and offloading vessel (FPSO)
has offloaded its first cargo by 31 May 2025.
H1 2024 H1 2023(1) Change %
Average production rate(2,3) boepd 8,400 9,200 -9%
Revenue $'000 113,328 129,722 -13%
Average realised oil price $/bbl 82 76 +8%
Average realised gas price $/boe 54e 80e -33%
Adjusted EBITDA(4) $'000 48,585 73,886 -34%
1. Comparative figures are pro forma and include the results from Kistos
Energy Norway as if it had been acquired on 1 January 2023. Financial
comparatives have been restated due to a change in the Group's presentational
currency - see note 1.4 to the Interim Financial Statements.
2. Total production rate includes gas, oil and natural gas liquids and is
rounded to the nearest 100 barrels of oil equivalent (boe) per day. Average
production rates include the impact from acquired businesses only from the
date of acquisition completion.
3. Sales and production volumes are converted to estimated boe using the
conversion factors in Appendix C to the Interim Financial Statements. Average
realised price is a non-IFRS measure. Refer to the definition within the
glossary.
4. Non-IFRS measures. See note 2.2.1 to the Interim Financial Statements for
definition and reconciliation to the nearest equivalent IFRS measure.
Outlook
In Norway, production at the Balder FPU is expected to remain steady, with the
addition of one new well from the Ringhorne platform anticipated to start
production before the end of the year. In August the operator of the Balder
Area, Vår Energi, announced that first oil from the Balder Future project is
now anticipated before the end of Q2 2025 rather than previous guidance of
start-up during Q4 2024. Vår also reported that capital expenditure on Balder
Future is forecast to increase by c.$400 million gross ($40 million net to
Kistos, of which $8.8 million is the approximate post-tax impact).
Approximately 75% of the additional capital expenditure is expected to be
incurred in 2025 and, in the meantime, the tax rebate in respect of 2023, to
be repaid to Kistos in December 2024, is expected to be approximately $84
million.
When Kistos acquired Mime Petroleum in May 2023 such a scenario was envisaged.
In the deal structuring with the bondholders (who effectively controlled the
company at the time) we protected Kistos from such a delay and cost increase
by modifying the terms of the $45 million Hybrid Bond. The Hybrid Bond was
restructured such that if 500,000 bbls (gross) was not lifted from the Jotun
FPSO before 31 May 2025 then the full $45 million is not payable and the
Hybrid Bond would be cancelled. Therefore, the Board of Kistos is confident
that there will be no adverse impact from the delay. Indeed, it is likely that
the negative effect of the delay and the increase in capital expenditure will
be significantly less than the positive effect of the Hybrid Bond not being
paid in full.
In reaching the decision to delay Balder Future, a key consideration was to
limit as much as possible the carryover of work on the Jotun FPSO into the
offshore installation and start-up phase. With all development wells completed
and all subsea production systems installed, the plan now is to complete the
FPSO fully onshore. Importantly, once it is on station, the Jotun FPSO will
enable future growth opportunities. Balder Phase V is being progressed,
including the drilling of six production wells to utilise the remaining subsea
template well slots to capture gross 2P reserves in excess of 30 mmboe.
Drilling of these wells will commence in the first half of 2025 and be
completed in 2026.
In the UK, the GLA joint venture partners continue to focus on progressing the
Glendronach development after agreeing that it represents a more attractive
opportunity than Edradour West at this time. In conjunction with expected new
third-party throughput across the Shetland Gas Plant (SGP), Glendronach would
extend the life of the existing facilities and give more certainty to
potential future developments, such as additional infill wells, and to other
third parties that are evaluating potential development projects in the area.
Kistos also expects that the announced change in operator of the GLA joint
venture (expected to complete in 2025, subject to regulatory approval) will
provide additional momentum in sanctioning development projects to extract
near-term value from the fields. On 21 August 2024 we announced that the NSTA
had awarded a 33(rd) round licence to a joint venture in which Kistos (33.3%)
is partnered with TotalEnergies (66.7%, operator). The seven full or part
blocks that have been offered reflect the full acreage that the partnership
applied for in January 2023 and are all within the vicinity of the existing
GLA footprint. The committed work programme is focussed on subsurface
evaluation techniques which should improve our estimation of the potential
prospectivity in the area before any decisions will be taken on whether to
progress with further work or not.
In the Netherlands, the second phase of Concept Select for the Orion oil
development was concluded successfully, and further progress is awaiting
clarity on the status of projects to extend the life of existing third-party
infrastructure. In the meantime, our team in the Netherlands continues to
evaluate opportunities to enhance production from existing wells at Q10-A and
to lower costs by working collaboratively with other users of the P15-D
platform. Kistos is also awaiting the outcome of the application to extend the
deadline to drill an appraisal well on the M10a and M11 licences, prior to
commencing any assessment phase planning work.
Kistos exited 2023 with 2P reserves of 27.9 mmboe. Production in H1 2024 was
1.5 mmboe, giving 2P reserves at 30 June of 26.4 mmboe. 2C contingent
resources were estimated to be 67.5 mmboe at the end of 2023. Production
guidance for full year 2024 is maintained in the 7,500-8,500 boepd range.
On the newly acquired gas storage assets in the UK, Kistos has already
successfully increased the working gas capacity of the Hill Top caverns by 24%
and our trading partner has traded the working gas capacity significantly more
actively than the previous owner. Kistos is now evaluating the economics of
recommissioning the Hole House facility, which has the potential to increase
the working capacity of the site by over 60%. This study is due to complete
during H2 2024.
The Group continues to evaluate several value-accretive business development
opportunities in the traditional energy sector, despite challenging fiscal
environments, and also in the energy transition space.
Chairman's Statement
I am delighted to be able to report Kistos' interim results covering the six
months to 30(th) June 2024. Adjusted EBITDA for the period was $49 million and
cash balances at the end of the period were $72 million. This was after
acquiring EDF's onshore gas storage business in the UK for £25 million and
$83 million of capital expenditure, mainly on the Balder Future project in
Norway.
Our balance sheet strength means we remain well placed to grow the business,
and after completing four acquisitions in four years from a standing start, we
continue to evaluate a pipeline of business development opportunities. While
we assess other potential acquisitions, we are also pursuing the organic
growth opportunities within our existing portfolio.
In Norway, Balder Phase V is progressing and entails the drilling of six new
production wells. These will utilise the remaining subsea template well slots
and capture gross 2P reserves of over 30 mmboe. Drilling of these wells will
commence in the first half of 2025 and be completed in 2026. In addition, the
Balder Phase VI project is being matured, with the aim of adding new subsea
facilities and wells, and an investment decision expected in the first half of
2025.
In conjunction with our JV partners, we continue to review the offshore UK
development plan for Glendronach, which previously passed all technical stage
gates with the operator and partners. This project, coupled with potential
infill drilling elsewhere in the GLA plus third-party opportunities, could
contribute substantially to the overall life extension of the area.
Finally, we have already increased the working gas capacity of the Hill Top
gas storage facility by 24%, despite only acquiring it towards the end of
April. We are now evaluating the economics of recommissioning the Hole House
facility, potentially increasing our exposure to the growing role that fast
cycle gas storage facilities will play in the energy transition.
On behalf of our shareholders, we remain intent on building a first-class
energy business that secures supplies to ease the energy crisis and drive
transition. We have taken great strides in a short period of time, and we will
continue to pursue rapid, disciplined growth both organically and through
acquisitions.
Andrew Austin
25 September 2024
Review of Operations
Norway production
Production
Net production from the Balder, Ringhorne and Ringhorne Øst fields (Kistos
10%, 10% and 7.4%, respectively) in the period averaged 2,800 boepd (H1 2023:
2,200 boepd; H1 2023 pro forma: 1,700 boepd), reflecting the increased number
of wells on production compared to the previous period. Production efficiency
in the first half of 2024 was 93%, which compares favourably with the 82%
achieved in the first half of 2023. 554 kbbl of crude was lifted from the
Balder floating production unit (FPU) in the period, comprising one part cargo
in a co-lifting with Vår in January under the legacy joint lifting
arrangement, and one full cargo (500 kbbl) under the new sales and lifting
arrangement that Kistos entered at the start of 2024. The average realised
price in the period was $82/bbl (H1 2023: $80/bbl).
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
fields. The project's target is to extract an additional c.150 mmboe from the
area, and to provide future expansion capacity to tie in extra wells to the
FPSO after the completion of Balder Future drilling programme.
The Jotun FPSO, which will act as an area hub and enable future growth
opportunities, is nearing completion and the mooring system has been
re-designed to reduce potential weather constraints for installation. Other
elements of the Balder Future project are largely complete. All subsea
facilities have been installed and all 14 production wells drilled and
completed, while the single water injector well was completed in July.
Nevertheless, in August the operator of Balder Future, Vår Energi, announced
that first oil from the project is now anticipated by the end of Q2 2025
rather than by the end of Q4 2024. In reaching the decision to delay start-up,
a key consideration was to limit as much as possible the carryover of work on
the Jotun FPSO into the offshore installation and start-up phase.
Looking forward, Balder Phase V is progressing, including the drilling of six
production wells to utilise the remaining subsea template well slots to
capture gross 2P reserves of over 30 mmboe. Drilling of these wells will
commence in the first half of 2025 with the COSL Pioneer semi-submersible
drilling rig and will be completed in 2026. In addition, the Balder Phase VI
project is being matured, with the aim of adding new subsea facilities and
wells, with an investment decision expected in the first half of 2025.
UK Storage
In April 2024, Kistos completed the acquisition of EDF's Hill Top Farm and
Hole House onshore gas storage assets in Cheshire, UK, for £25 million ($31.1
million) payable in cash at completion (less closing working capital
adjustments) (the 'Gas Storage Acquisition'). The Gas Storage Acquisition is
in line with the Group's strategy to pursue opportunities that align with the
energy transition and provides diversification of the asset portfolio into a
stable marketplace that offers significant growth potential.
As purchased, Hill Top's working gas capacity was 17.8 million therms,
accounting 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.
Following the acquisition, Kistos successfully integrated the existing staff
and infrastructure and is working closely with its trading partner to maximise
value via the placing of intrinsic seasonal gas trades and opportunistic
extrinsic trades that take advantage of gas price volatility.
In the period from acquisition to 30 June, 17.8 million therms were traded for
the purpose of intrinsic trades (a combination of seasonal gas trades as well
as Operating Margins contract placed with National Gas) whilst 191 million
therms of gas were traded for extrinsic benefit, and 71 million therms of gas
were physically moved. This represents a significant increase in the level of
activity under the previous ownership. Revenue in the period from acquisition
to 30 June was $1.9 million. This excludes unrealised gains for intrinsic
seasonal trades that have not yet settled.
During May and June, we successfully undertook the fifth and final phase of a
'soft cycling' relaxation trial, the purpose of which was to monitor the
integrity of the five caverns at Hill Top Farm during a period where pressure
was as close to the original operating design pressure as possible. Following
completion of the trial, independent geotechnical experts Geostock Group
provided a report that stated the facility can operate as per its original
design parameters. This means 4.2 million therms previously categorised as
excess cushion gas are now able to be included within the working gas total,
representing an uplift of 24% to the working gas volume at Hill Top, therefore
increasing the amounts available to be moved and/or traded each day. The
benefits of this additional working gas volume (including proceeds from
selling this previously trapped cushion gas back to the market) will be seen
in the second half of 2024.
We are now evaluating the economics of recommissioning the Hole House facility
and expect our evaluation to conclude during the second half of 2024. Hole
House, developed specifically for gas storage, was operational from 2001
through to 2018 and requires approximately one-third as much cushion gas as
Hill Top for the same amount of working gas. Post-2018 a period of
decommissioning the caverns by means of re-brining them commenced and three
out of the total four caverns are now nearly all brine filled, with cushion
gas sold to market.
Netherlands production
Q10-A
Net Q10-A (Kistos 60% and operator) production in the first half of 2024 was
2,200 boepd compared to 3,100 boepd in the first half of 2023. Production was
adversely impacted by an unplanned two-week shutdown caused primarily by the
failure of fire water pumps on the TAQA-operated P15-D platform, the start of
the planned P15-D annual maintenance turnaround which commenced at the end of
June and ongoing natural reservoir decline.
Kistos continues to evaluate opportunities to enhance value from the Q10-A gas
field, working 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 would be to extend the economic life of the hub for the
benefit of all users. Kistos has also reviewed its own underlying cost as an
operator of Q10-A and optimisations have been made, including taking a
decision to move office in Q3 2024, and reducing head count through synergies
realised through integration of our Kistos Energy Norway team into the
management of elements of our Dutch business.
Average realised gas prices in the period fell by 35% to €30/MWh from
€46/MWh in H1 2023. In conjunction with lower production rates, this caused
total revenue in the period to decrease by 52% to $21.0 million compared to
$43.4 million in H1 2023.
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. During the first half of 2024, the second
phase of Concept Select continued, with the technical work concluding during
Q2 2024. Kistos subsequently received indicative commercial terms from the
operator of P15-D and further progress is now awaiting clarity on life
extension projects affecting third party infrastructure. These are necessary
to ensure Orion will have a viable economic life.
Our team in the Netherlands continues to evaluate opportunities to enhance
production from existing wells at Q10-A and to lower costs by working
collaboratively with other P15-D users.
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 to apply for a permit to drill an appraisal well prior to 28 February
2024, 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 permit application deadline. As this is a request to change
the conditions of the licence, the authorities are now formally considering
our request. To date, no decision has been made by the authorities and the
project therefore remains on hold until such time a response is received.
Other
The Q11-B well, drilled as part of the 2021-22 campaign and suspended in
February 2022, continues to be monitored with an annual bubble survey and the
next one is anticipated to be undertaken later this year. This offshore
testing will confirm the integrity of the well suspension, and an extension to
the suspension consent has been received meaning well abandonment will now
take place in 2026 at the earliest, a year later than previously indicated.
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 with EBN (40%). Initial evaluation of the acreage
concluded in H1 2024, and a further desktop work programme was agreed with
EBN. Q10-Gamma remains the highest ranked prospect that has been identified in
our exploration acreage.
Onshore, after concluding the safe abandonment of three wells (HRK-1, DKK-3
and DKK-4) at the end of 2022, Kistos continued work on the remaining
decommissioning activities. This primarily involves removing 19 kilometres of
buried pipelines and a trial was conducted during the first quarter of the
year that successfully removed sections of pipeline up to 0.4 kilometres at a
time, using a new pulling method technique in order to minimise disturbance to
landowners and other stakeholders as opposed to the traditional method of open
excavation. This enabled the main phase of pipeline removal to commence in
June 2024 with a lower budget than initially proposed. We expect the works to
conclude by Q3 2025, thus satisfying all our remaining onshore abandonment
obligations in the Netherlands.
UK production
Greater Laggan Area
Net production from Kistos' share in the Greater Laggan Area (GLA) (Kistos
20%) in the six months to 30 June 2024 was above expectations at an average
rate of 3,400 boepd (H1 2023: 4,300 boepd). The first half of 2024 included a
major planned 21-day shutdown of the Shetland Gas Plant (SGP) in May, which
was completed safely and on schedule.
Production from the single well on the Edradour field remains suspended. The
GLA joint venture continues to monitor the well and its potential restart, but
at the present time it is expected to remain offline except for short periods
to observe the well's performance.
Average realised gas prices in the period were 72p/therm versus 108p/therm a
year earlier. Combined with a 21% reduction in average daily production, this
resulted in a 45% decrease in revenue to $35.8 million from $65.6 million in
H1 2023.
Following the acquisition of a 4D seismic survey over the GLA fields in 2023,
completion of the data processing is now mostly complete, and the joint
venture is in the process of performing the interpretation and integration
work required to mature further opportunities over the fields. The primary aim
of the campaign was to de-risk potential infill drilling opportunities and to
provide better reservoir monitoring and management across the GLA as a whole.
While the studies and their interpretation are ongoing, initial indications
are that there remains potential to drill infill wells on the producing
fields.
After further evaluation of the Edradour West development, the partners agreed
that, due to reservoir uncertainties, no further work would be undertaken
towards its development at the present time. On Glendronach, which previously
passed all technical stage gates with the operator and partners, the JV
continues to review its development plan and to examine opportunities to
reduce costs.
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 onstream, will significantly
reduce unit operating costs for the GLA partners while providing a life
extension for the existing GLA fields.
Subsequent to the period end and in partnership with TotalEnergies as
operator, Kistos was awarded a 33% interest in seven new blocks or part blocks
within the Greater Laggan Area as part of the 33(rd) Offshore licencing round.
The blocks were previously held by the GLA JV prior to Kistos' acquisition of
its 20% non-operated stake from TotalEnergies in 2022. The award of these
blocks, which include the previously identified Ballechin exploration
prospect, supports the GLA JV partners' efforts to identify opportunities to
extend the life of existing infrastructure and maximise economic output. The
work programme includes studies on a seismic dataset that is already owned by
the JV partners.
Financial Review
Unaudited results for the 6 months ending 30 June 2024
30 June 2024 30 June 2023 30 June 2023
(actual)(6) (actual) (pro forma)(7)
Total production(1) kboe 1,544 1,433 1,659
Production rate(1) boepd 8,400 9,600 9,200
Revenue $'000 113,328 113,805 129,722
Average realised sales price(2) $/boe 65 80 79
Unit opex(3) $/boe 29 21 25
Adjusted EBITDA(4) $'000 48,585 72,220 73,886
(Loss)/profit before tax $'000 (40,287) 5,281 n/a
Basic earnings per share $ (0.21) 0.18 n/a
Net cash flow from operations $'000 (27,351) 102,536 n/a
Unrestricted cash at end of period $'000 69,950 270,072 270,072
Net debt(5) $'000 (174,943) (35,243) (35,243)
Financial results are prepared in accordance with IFRS, unless otherwise noted
below:
1 Total production rate includes gas, oil and natural gas liquids and is
rounded to the nearest 100 barrels of oil equivalent per day. 'Actual'
production rates include the impact from acquired businesses only from the
date of acquisition completion. Sales and production volumes are converted to
estimated boe using the conversion factors in Appendix C to the Interim
Financial Statements.
2. Non-IFRS measure. Refer to the definition within the glossary.
3. Non-IFRS measure. Refer to the definition within the glossary and
reconciliation in Appendix B3.
4. Non-IFRS measure. Refer to the definition within the glossary and
reconciliation in note 2.2.1.
5. Non-IFRS measure. Refer to the definition within the glossary and
reconciliation in Appendix B2.
6. Actual results for 2024 include revenue and Adjusted EBITDA from the UK
Storage segment from the date of the Gas Storage Acquisition (23 April 2024).
No pro forma information is provided in respect of the gas storage assets as
management consider the pre-acquisition trading result is not representative
of future operations: (a) the pre-acquisition trading result in 2024 comprised
primarily of the close-out of positions placed by the previous operator in
2023; and (b) the pre-acquisition trading arrangement resulted in a different
presentation and accounting treatment of trading activity, which are not
comparable to the current activity.
7. Pro forma figures for 2023 include results from Kistos Energy Norway as if
it had been acquired on 1 January 2023. The acquisition completed on 23 May
2023
The Group changed its presentation currency from Euros to US Dollars (USD)
effective 1 January 2024. The presentation currency has been changed as the
Group's debt is now all denominated in USD, and an increasing proportion of
the Group's revenues is derived from the sale of crude oil which is priced in
USD.
Production and revenue
Actual production on a working interest basis averaged 8,400 boepd in the
first half of 2024 (H1 2023: 9,600 boepd reported, 9,200 boepd pro forma).
This represents a decrease of 9% (on a pro forma basis) on the equivalent
period from a year earlier and reflects the continued natural decline in
production from our UK and Dutch producing assets and the planned spring 2024
shutdown of the Shetland Gas Plant, partially offset by a number of new wells
coming on-stream in Norway.
The Group's average realised price across gas and oil sales during the period
was $65/boe, and total revenue from the sale of our oil and gas production was
$113.3 million, compared with $80/boe and $113.8 million reported in H1 2023
(H1 2023 pro forma: $79/boe and $129.7 million), primarily reflecting weaker
UK and European gas prices in the current period.
In the Netherlands, the average realised gas price for the period was
€30/MWh (H1 2023: €46/MWh). In the UK, the average realised gas price for
the period was 72p/therm (H1 2023: 108p/therm). The average realised oil price
from crude oil sales in Norway was $82/bbl (H1 2023: $70/bbl), reflecting the
norm price differential applied by the Norwegian Petroleum Price Council to
Balder crude for the period.
Our gas storage assets contributed $1.9 million of revenue in the period from
acquisition, generated from trading activities and one-off sales of excess
cushion gas from the currently decommissioned Hole House facility.
Operating costs and unit opex
Unit opex for the period (which excludes non-cash accounting movements in
inventory and operating costs from the UK Storage segment) was $29/boe (H1
2023: $21/boe; H1 2023 pro forma: $25/boe), reflecting the impact of decreased
productions rates in the UK and Netherlands against broadly flat operating
costs.
Adjusted EBITDA
The Group reported Adjusted EBITDA of $48.6 million in the six months to 30
June 2024. The decline versus the comparable period of 2023 was primarily
driven by lower gas prices and gas production volumes.
Capital expenditure
Cash capital expenditure in the first half of 2024 was $83.2 million, almost
all of which related to the Balder Future project in Norway. It comprised
drilling, refurbishment costs on the Jotun FPSO, and other facilities. Most of
Kistos' capital expenditure in the second half of the year is also anticipated
to be incurred on the Balder Future project in Norway, with no drilling or
well intervention campaigns planned in the UK or in the Netherlands. 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 tax receivable in respect of 2023
Norwegian tax losses (primarily generated by capital expenditure in that year)
is anticipated to be approximately NOK 901 million ($84.3 million), not
including accrued interest, to be received in December 2024. The tax
receivable generated by losses incurred in the first half of 2024 is estimated
to be NOK 409 million ($38.2 million), to be received in December 2025.
Profit and loss before tax
The statutory operating loss for the period ended 30 June 2024 was $13.1
million (H1 2023: operating loss of $7.7 million). After net finance costs of
$27.1 million (2023: net finance income of $2.4 million), principally relating
to bond interest expense and foreign exchange movements offset by interest
income and a gain on the accounting remeasurement of the Hybrid Bond, a loss
before tax of $40.3 million was recorded (H1 2023: loss before tax of $5.3
million).
Tax
The net accounting tax credit for the period was $23.0 million, arising
primarily from tax losses generated in Norway and deferred tax movements in
the UK. The net current tax charge for the period, (which only reflects tax
due or receivable on profits or losses made in the period) was $7.3 million,
representing an effective rate of 14% on EBITDA (H1 2023: $19.8 million, and
an effective rate of 19% on EBITDA). This reflects the statutory headline
rates of 75%, 78% and 50% applicable to oil and gas production activities in
the UK, Norway and Netherlands respectively and the statutory headline rate of
25% applicable to onshore UK activities, offset by capital allowances for
capital expenditure on the Balder Future project. Cash tax payments for the
period were $73 million (H1 2023: $41.2 million), primarily relating to the
settlement of our UK tax liabilities on 2022 profits. 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 plus interest in December 2023, Kistos expects to receive 901
million NOK ($84.2 million) in December 2024 (in addition to accrued
interest).
The current tax liability at 30 June 2024 was $80.5 million (31 December 2023:
$142.1 million). Both periods include €47 million ($50.4 million) provided
for in respect of the Solidarity Contribution Tax. However, the Group believes
the relevant Dutch subsidiary, Kistos NL2 BV, is out of scope (see note 6.3 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.
Debt and liquidity
Unrestricted cash balances at the end of the period were $70.0 million (31
December 2023: $214.8 million). Net debt at 30 June 2024 was $174.9 million
(31 December 2023: $26.8 million). Pre-tax operating cashflow for the period
was $45.7 million (H1 2023: $143.7 million), reflecting the decline in average
production rates and weaker commodity prices, and favourable working capital
movements in the comparative period arising from the settlement of gas sales
made in December 2022.
The face value of the Group's bond debt at 30 June 2024 was $289.9 million,
comprising USD-denominated bonds issued by its Norwegian subsidiary. $45
million of this is non-interest-bearing, and only fully payable in the event
500,000 bbl (gross) have been offloaded and sold from the Jotun FPSO by 31
December 2024. This amount will decline to $30 million from 1 January 2025 to
28 February 2025, to $15 million from 1 March 2025 to 31 May 2025, and to zero
thereafter. The remaining debt comprises a $120 million bond (face value now
$128.1 million) and a $105 million bond (face value now $116.8 million). 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. Further details on the bonds are
outlined in note 5.1 to the financial statements.
The Group has no commodity price hedges in place for the sale of its oil and
gas entitlements. Trading activities relating to the Group's gas storage
assets are undertaken on the Group's behalf by its third-party trading
partner, which also funds and owns the working gas in the caverns. Therefore,
the Group has no mark-to-market or margin exposure on trades placed in
relation to those activities in the ordinary course of business.
Principal Risks and Uncertainties
The Directors do not believe that the principal risks and uncertainties have
changed since the publication of Kistos Holdings plc's 2023 Annual Report
dated 10 May 2024. There are a number of potential risks and uncertainties
that could have a material impact on the Group's performance over the
remaining six months of the financial year and could cause actual results to
differ materially from expected and historical results. A detailed explanation
of the risks summarised below can be found in the section headed "Principal
Risks and Uncertainties" on page 24 of the Kistos Holdings plc 2023 Annual
Report dated 10 May 2024, which is available at www.kistosplc.com.
The key headline risks relate to the following:
· Political
· Growth of business and reserves base
· Climate change and energy transition
· Cyber security
· Joint venture activity
· HSE and compliance
· Hydrocarbon production and operational performance
· Project delivery
· Retention of key personnel
· Commodity price
· Liquidity
· Decommissioning costs and timing
· Taxation
Our Environmental, Social and Governance Ambitions
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 included as part of ongoing operational and project decisions.
The 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 provide 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.
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.
One of Kistos' ESG goals is to achieve carbon neutrality for Scope 1 and Scope
2 emissions by 2030. In the Netherlands, 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, with a Scope 1 emissions intensity level of
less than 0.01 kg CO(2)e/boe.
Across the Q10-A platform in the Netherlands, as well as our non-operated
interests in the GLA offshore the UK and on the NCS, the Group's Scope 1 and
Scope 2 emissions intensity ratios are below the North Sea average. They are
also estimated to be significantly lower than the average CO(2) 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 1 .
To maintain safe operating conditions on our gas storage site in Cheshire, it
is occasionally necessary to vent and purge amounts of natural gas into the
atmosphere. In the period from acquisition (23 April 2024) to 30 June 2024, 13
tonnes of natural gas was released because of planned shutdowns and unplanned
events (equivalent to approximately 355 tonnes of CO(2,) which are classified
as Scope 1 emissions) 2 . As the gas storage assets do not produce, nor
consume hydrocarbons, we are not required to report emissions associated with
this asset within the group's average emissions intensity.
In the 6 months to 30 June 2024, our share of total Scope 1 and 2 emissions
were estimated at 20,100 tonnes of CO(2) equivalent (CO(2)e). No flaring was
undertaken in the current period. The estimated production emissions intensity
(which excludes emissions from our gas storage assets, which do not produce
hydrocarbons) was 13 kg CO(2)e/boe (Scope 1 and 2).
Cautionary Statement About Forward-Looking Statements
This half-year results announcement contains certain forward-looking
statements. All statements other than historical facts are forward-looking
statements. Examples of forward-looking statements include those regarding the
Group's strategy, plans, objectives or future operating or financial
performance, reserve and resource estimates, commodity demand and trends in
commodity prices, growth opportunities, and any assumptions underlying or
relating to any of the foregoing. Words such as 'intend', 'aim', 'project',
'anticipate', 'estimate', 'plan', 'believe', 'expect', 'may', 'should',
'will', 'continue' and similar expressions identify forward-looking
statements. Forward-looking statements involve known and unknown risks,
uncertainties, assumptions and other factors that are beyond the Group's
control. Given these risks, uncertainties and assumptions, actual results
could differ materially from any future results expressed or implied by these
forward-looking statements, which speak only at the date of this report.
Important factors that could cause actual results to differ from those in the
forward-looking statements include: global economic conditions, demand, supply
and prices for oil, gas and other long-term commodity price assumptions (as
they materially affect the timing and feasibility of future projects and
developments), trends in the oil and gas sector and conditions of the
international markets, the effect of currency exchange rates on commodity
prices and operating costs, the availability and costs associated with
production inputs and labour, operating or technical difficulties in
connection with production or development activities, employee relations,
litigation, and actions and activities of governmental authorities, including
changes in laws, regulations or taxation. Except as required by applicable
law, rule or regulation, the Group does not undertake any obligation to
publicly update or revise any forward-looking statements, whether as a result
of new information, future events or otherwise. Past performance cannot be
relied on as a guide to future performance.
Interim Financial Statements (unaudited)
Condensed consolidated income statement
$'000 Note 6 months ended 6 months ended
30 June 2024 30 June 2023
(restated)
Revenue 2.1 113,328 113,805
Other income 196 28
Exploration expenses (481) (278)
Production and operating costs (54,601) (35,984)
Development expenses (154) (413)
Abandonment expenses (1,794) -
General and administrative expenses (8,894) (5,791)
Depreciation and amortisation 2.3, 2.4 (60,611) (50,426)
Impairment 2.4 (132) (32,231)
Release of contingent consideration 7.1 - 3,568
Operating loss (13,143) (7,722)
Interest income 3.2 4,092 2,846
Interest expenses 3.2 (19,499) (4,098)
Foreign exchange movements and other net finance costs 3.2 (11,737) 3,693
Net finance (costs)/income (27,144) 2,441
Loss before tax (40,287) (5,281)
Tax credit 6.1 23,045 19,784
(Loss)/Profit for the period (17,242) 14,503
Basic (loss)/earnings per share ($) 3.1 (0.21) 0.18
Diluted (loss)/earnings per share ($) 3.1 (0.21) 0.17
Condensed consolidated statement of other comprehensive income
$'000 6 months ended 6 months ended
30 June 2024 30 June 2023
(restated)
(Loss)/profit for the period (17,242) 14,503
Items that may be reclassified to profit or loss:
Foreign currency translation differences (2,443) 1,632
Total comprehensive (loss)/income for the period (19,685) 16,135
Condensed consolidated balance sheet
$'000 Note 30 June 2024 31 December 2023 31 December 2022
(restated) (restated)
Non-current assets
Goodwill 2.4 51,984 54,239 11,642
Intangible assets 2.4 33,748 34,591 46,446
Property, plant and equipment 2.3 523,590 455,286 302,399
Non-current tax receivable 6.2.1 38,237 - -
Deferred tax assets 6,199 2,133 606
Investment in associates 65 65 65
Other long-term receivables 171 165 109
653,994 546,479 361,267
Current assets
Inventories 17,952 22,544 10,373
Trade and other receivables 4.2 27,894 29,215 58,463
Current tax receivable 6.2.1 84,248 88,690 -
Cash and cash equivalents 4.1 72,007 214,974 226,896
202,101 355,423 295,732
Total assets 856,095 901,902 656,999
Equity
Share capital and share premium 9,979 9,979 9,979
Other equity 3,897 3,897 -
Other reserves 72,299 74,714 71,492
(Accumulated loss)/retained earnings (15,331) 1,911 28,504
Total equity 70,844 90,501 109,975
Non-current liabilities
Abandonment provision 2.5 258,706 231,283 132,239
Bond debt 5.1 236,877 237,936 86,473
Deferred tax liabilities 152,604 144,146 126,687
Other non-current liabilities 4.4 5,695 678 4,495
653,882 614,043 349,894
Current liabilities
Trade payables and accruals 4.3 35,077 44,477 22,821
Other current liabilities 4.4 14,100 6,152 18,321
Current tax payable 6.2.2 80,474 142,125 153,222
Abandonment provision 2.5 1,718 4,604 2,766
131,369 197,358 197,130
Total liabilities 785,251 811,401 547,024
Total equity and liabilities 856,095 901,902 656,999
Condensed consolidated statement of changes in equity
$'000 Share capital and share premium Other equity Other reserves Retained earnings Total equity
At 1 January 2023 (restated) 9,979 - 71,492 28,504 109,975
Profit for the period - - - 14,503 14,503
Movement in the period - - 1,632 - 1,632
Total comprehensive income for the period - - 1,632 14,503 16,135
Share-based payments - - 111 - 111
Issue of warrants - 3,897 - - 3,897
At 30 June 2023 (restated) 9,979 3,897 73,235 43,007 130,118
At 1 January 2024 (restated) 9,979 3,897 74,714 1,911 90,501
Loss for the period - - - (17,242) (17,242)
Movement in the period - - (2,443) - (2,443)
Total comprehensive loss for the period - - (2,443) (17,242) (19,685)
Share-based payments - - 28 - 28
At 30 June 2024 9,979 3,897 72,299 (15,331) 70,844
Condensed consolidated cash flow statement
$'000 Note 6 months ended 6 months ended
30 June 2024 30 June 2023
(restated)
Cash flows from operating activities:
(Loss)/profit for the period (17,242) 14,503
Tax credit 6.1 (23,045) (19,784)
Net finance costs/(income) 3.2 27,144 (2,441)
Depreciation and amortisation 2.3, 2.4 60,611 50,426
Impairment 2.4 132 32,231
Change in fair value and releases of contingent consideration - (3,568)
Share-based payment expense 28 111
Income tax paid (73,011) (41,199)
Interest income received 1,789 2,838
Abandonment costs paid (757) (29)
Decrease in trade and other receivables 3,543 17,460
(Decrease)/increase in trade and other payables (11,518) 44,875
Decrease in inventories 4,975 7,142
Net movement in other working capital items - (29)
Net cash flow from operating activities (27,351) 102,536
Cash flows from investing activities:
Payments to acquire tangible and intangible fixed assets (83,164) (49,816)
Consideration paid for Gas Storage Acquisition, net of cash acquired 2.7 (22,070) -
Net cash acquired in Mime Acquisition - 7,802
Contingent consideration paid for GLA Acquisition - (17,231)
Net cash flow from investing activities (105,234) (59,245)
Cash flows from financing activities:
Interest paid (3,447) (5,141)
Lease repayments and other financing cash flows (1,760) (1,227)
Net cash flow from financing activities (5,207) (6,368)
(Decrease)/increase in cash and cash equivalents (137,792) 36,923
Cash and cash equivalents at beginning of period 214,974 226,896
Effects of foreign exchange rate changes (5,175) 6,253
Cash and cash equivalents at end of period 72,007 270,072
Notes to the interim condensed consolidated financial statements
Section 1 General information and basis of preparation
1.1 General information
These condensed consolidated financial statements for the six-month period
ended 30 June 2024 have been prepared in accordance with IAS 34 Interim
Financial Reporting and AIM Rule 18. These condensed consolidated financial
statements, along with the management report above, represent a 'half-yearly
report' as referred to in the AIM Rules. Accordingly, they do not include all
the information required for a full annual financial report. These condensed
consolidated financial statements are unaudited and do not constitute
statutory accounts as defined in section 434 of the Companies Act 2006 and
should be read in conjunction with the 2023 Annual Report and Accounts.
Interim period results are not necessarily indicative of results of operations
or cash flows for an annual period. The condensed consolidated financial
statements have not been subject to review or audit by independent auditors;
therefore, all figures are unaudited (unless otherwise stated). The Group's
business is not inherently seasonal, but gas prices (and therefore revenue
from gas sales) are typically higher in the European winter months than the
summer.
These condensed consolidated financial statements were authorised for issue by
Kistos Holdings plc's Board of Directors on 25 September 2024.
1.2 Going concern
These condensed consolidated financial statements have been prepared in
accordance with the going concern basis of accounting. The forecasts and
projections made in adopting the going concern basis take into account
forecasts of commodity prices, production rates, operating and general and
administrative (G&A) expenditure, committed and sanctioned capital
expenditure, and the timing and quantum of future tax payments. To assess the
Group's ability to continue as a going concern, management evaluated cash flow
forecasts for the period to December 2025 (the going concern period) by
preparing a base case forecast and various downside sensitivities. The base
case assumed the following:
· First oil from the Jotun FPSO in mid-2025 in line with the latest
update provided by the operator (note 2), resulting in the entire $45 million
Hybrid Bond being cancelled.
· 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 NOK901 million (excluding interest) is received
in December 2024 in respect of Norwegian tax losses incurred in 2023, and a
further rebate is received in December 2025
· 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.
· Ongoing cash flows from the Gas Storage Acquisition in line with
existing budgets and conservative estimates from profits arising from gas
trading activities.
· The 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 103p/therm, €41/MWh and $75/bbl across
the going concern period)
The base case forecast indicated that the Group would be able to maintain
sufficient 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.
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; and
· adverse movement in foreign exchange rates.
The outcome of applying one or more of these reasonably plausible downside
scenarios against the base case supported the going concern conclusion.
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 ($50.4 million). A return in respect of this tax was filed by
the required deadline of 31 May 2024. As set out in note 6.3, the Group
believes 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 is likely to
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 Belastingdienst (Dutch Tax Authority) demand an earlier
payment, or require payment prior to any appeal being admitted, this would
have a material adverse effect on the Group's liquidity.
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 £69 million ($88
million), which the Group satisfied via the purchase of surety bonds at an
approximate cost of $3 million. The redetermination in respect of 2025,
subject to final agreement by the JV partners, is an obligation of £63
million ($80 million), with renewed surety bonds (or other arrangements, if
applicable) to be put in place by the end of 2024. As part of the going
concern assessment the Directors sought advice from surety bond brokers and
other advisors regarding the Group's ability to cover the 2025 obligation
fully via surety bonds given current market conditions and the risk appetite
of insurance providers. 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 in full or part, significantly reducing available liquidity. Based on
the advice received and status of discussions with surety and other insurance
providers, the Directors are of the view that the Group will be able to meet
the current DSA provisions and those required in the foreseeable future.
Based on the assessments made, an adverse movement in either of these key
assumptions could result in the Group breaching its liquidity covenant in
mid-2025. The Group has 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. 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 5.1), for which
up to $60 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). The Group has arranged a short-term
unsecured financing facility for up to $15 million which is available to be
drawn down until the end of 2024. This facility will enable to the Group to
meet any short-term liquidity pressures that may arise from adverse movements
to production rates, commodity prices and/or increases to capital expenditure
in the intervening period prior to the Norwegian tax rebate being received in
December 2024. The Group is of the view that the facility's availability could
be extended into 2025, although this is subject to agreement with the
financing provider. 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.
These condensed consolidated financial statements do not include any
adjustments that may result from the outcome of these uncertainties.
1.3 Material accounting policies
The material accounting policies used in these condensed consolidated
financial statements are consistent with those used in the Group's annual
financial statements for the year ended 31 December 2023, with the exception
of a change to the presentation currency of the Group's financial statements
(note 1.4) and new material accounting policies outlined below which have been
introduced following the Gas Storage Acquisition:
Property, plant and equipment
Cushion gas, being that volume of gas that cannot be withdrawn from gas
storage caverns while they remain in use, is classified within 'Property,
plant and equipment' and is not depreciated.
Freehold land is held at cost and is not depreciated.
Certain amended accounting standards and interpretations became applicable for
the current reporting period. The Group did not have to change its accounting
policies or make retrospective adjustments as a result of adopting these
amendments, as the Group's accounting policies are already aligned with the
amended standards, or they are not relevant to the Group's business. There are
new and revised accounting standards in issue that will become effective for
future periods, but it is not expected these standards and interpretations
will have a material impact on the Group's financial statements upon adoption.
Other minor reclassifications have been made to the presentation of certain
line items in the comparative financial statements and the notes in line with
the presentation within the 2023 annual financial statements:
· On the consolidated cash flow statement, interest income received
is now presented within 'Net cash flow from operating activities' (previously
within 'Net cash flow from financing activities').
· On the consolidated balance sheet, balances relating to amounts
due to joint operators are presented within 'Trade payables and accruals'
(previously within 'Other liabilities').
In preparing these condensed consolidated financial statements, management has
made judgements, estimates and assumptions that affect the application of
accounting policies and the reported amounts of assets and liabilities, income
and expense. Actual results may differ from these estimates. The significant
judgements made by management in applying the Group's accounting policies and
the key sources of estimation uncertainty were the same as those that applied
to the audited annual financial statements at 31 December 2023, with the
addition of a critical judgement that applied in accounting for the Gas
Storage Acquisition:
· As substantially all the fair value of the gross assets acquired
in the Gas Storage Acquisition was concentrated in a group of similar
identifiable assets, the 'concentration test' provisions of IFRS 3 Business
Combinations were met;
· Presumption of going concern
· Estimate of abandonment provisions
· Estimation of reserves and contingent resources
· Assessment of capitalised borrowing costs
· Identification of impairment indicators
· Accounting treatment of the Hybrid Bond
· Recognition of Solidarity Contribution Tax provision
1.4 Foreign currencies and translation
Items included in the financial statements of each of the Group's entities are
measured using the currency of the primary economic environment in which each
entity operates (the functional currency). Transactions in currencies other
than the functional currency are translated to the entity's functional
currency at the foreign exchange rates at the date of the transactions.
Foreign exchange gains and losses resulting from the settlement of monetary
assets and liabilities denominated in foreign currencies are recognised in the
income statement. All UK-incorporated entities in the Group, including Kistos
Holdings plc, have a functional currency of pounds Sterling (GBP). All
Dutch-incorporated entities have a functional currency of euros (EUR).
Norwegian-incorporated entities have a functional currency of Norwegian Krone
(NOK).
The Group changed its presentation currency from Euros (EUR) to US Dollars
(USD) effective 1 January 2024. The presentation currency has been changed as
the Group's debt is now all denominated in USD, and an increasing proportion
of the Group's revenues is derived from the sale of crude oil which is priced
in USD.
A change in presentation currency represents a change in accounting policy
under IAS 8 'Accounting Policies, Changes in Accounting Estimates and Errors'
and therefore requires the restatement of comparative financial information.
The results and balance sheet of all the Group entities that have a functional
currency different from the presentation currency were translated into the
presentation currency as follows:
· Assets and liabilities for each balance sheet presented were
translated at the closing rate at the date of that balance sheet (except for
certain items in equity which are translated at the historical rate);
· Income and expenditure and cash flows were translated at average
exchange rates for the periods; and
· The effects of translating the Group's financial results and
financial positions into USD was recognised within 'Other comprehensive
income' and against the foreign currency translation reserve (within 'Other
reserves' on the balance sheet).
1.5 Significant events in the current period
The financial position and performance of the Group was affected by the
following events and transactions during the six months ended 30 June 2024:
· Based on a preliminary assessment, the acquisition of EDF Energy
(Gas Storage) Limited in April 2024 resulted in the recognition of, inter
alia, $69.0 million of property plant and equipment and a net cash outflow of
$22.1 million in respect of the transaction itself.
· Cash outflows of $73.0 million in respect of tax liabilities.
Section 2 Oil and gas operations
2.1 Revenue
$'000 6 months ended
30 June 2024
Netherlands Production Norway Production UK Production UK Storage Total
Sales of produced natural gas 21,039 - 28,394 1,912 51,345
Sales of produced hydrocarbon liquids - 54,544 7,439 - 61,983
Revenue from external customers 21,039 54,544 35,833 1,912 113,328
3$'000 6 months ended
30 June 2023
Netherlands Production Norway Production UK Production Total
Sales of crude oil and liquids - 4,881 11,893 16,774
Sales of natural gas 43,366 - 53,665 97,031
Revenue from external customers 43,366 4,881 65,558 113,805
2.2 Segmental information
The performance of the Group is monitored by the Executive Directors
(comprising the Executive Chairman, Chief Executive Officer and Chief
Financial Officer) who consider the business from both a product and a
geographic perspective.
2.2.1 Adjusted EBITDA
The Executive Directors use Adjusted EBITDA as a measure of profit and 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 that 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 6 months ended 6 months ended
30 June 2024 30 June 2023
(restated)
Adjusted EBITDA by segment:
Netherlands Production 12,855 33,212
Norway Production 26,401 1,750
UK Production 13,632 40,110
UK Storage (1,873) -
All other segments (2,430) (2,852)
Group Adjusted EBITDA 48,585 72,220
Development expenses (154) (413)
Share-based payment expense (29) (111)
Depreciation and amortisation 2.3, 2.4 (60,611) (50,426)
Impairment 2.4 (132) (32,231)
Transaction costs (802) (329)
Change in fair value and releases of contingent consideration 7.1 - 3,568
Operating loss (13,143) (7,722)
Net finance (costs)/income 3.2 (27,144) 2,441
Loss before tax (40,287) (5,281)
2.3 Property, plant and equipment
$'000 Freehold land Oil and gas production assets Gas storage facilities and other Total
Cost
At 1 January 2024 (restated) - 739,848 2,483 742,331
Acquisitions (note 2.7) 2,091 - 66,467 68,558
Additions - 86,810 1,121 87,931
Foreign exchange differences 8 (37,862) 538 (37,316)
At 30 June 2024 2,099 788,796 70,609 861,504
Accumulated depreciation and impairment
At 1 January 2024 (restated) - (286,170) (875) (287,045)
Depreciation charge for period - (59,923) (453) (60,376)
Foreign exchange differences and other movements - 9,485 22 9,507
At 30 June 2024 - (336,608) (1,306) (337,914)
Net book value at 31 December 2023 (restated) - 453,678 1,608 455,286
Net book value at 30 June 2024 2,099 452,188 69,303 523,590
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.
2.4 Intangible assets and goodwill
$'000 Goodwill Exploration and evaluation assets Other Total
Cost
At 1 January 2024 (restated) 58,058 129,600 754 188,412
Acquisitions (note 2.7) - - - -
Additions - 104 147 251
Foreign exchange differences and other movements (2,281) (2,495) (22) (4,798)
At 30 June 2024 55,777 127,209 879 183,865
Accumulated amortisation and impairment
At 1 January 2024 (restated) (3,819) (95,534) (229) (99,582)
Amortisation charge for the period - - (235) (235)
Foreign exchange differences and other movements 26 1,750 40 1,816
Impairment and write-off of exploration assets - 14 (146) (132)
At 30 June 2024 (3,793) (93,770) (570) (98,133)
Net book value at 31 December 2023 (restated) 54,239 34,066 525 88,830
Net book value at 30 June 2023 51,984 33,439 309 85,732
Exploration and evaluation assets include the exploration licence portfolio
acquired as part of the GLA Acquisition, the Orion oil prospect on the Q10-A
licence and exploration prospects in Norway. The Group's oil and gas licence
interests are shown in note 2.6. Exploration write-offs in the period relate
to additional residual costs incurred in the period on the Benriach licence,
which was deemed sub-commercial following evaluation of drilling results in
2023.
2.5 Abandonment provision
$'000 Note 6 months ended
30 June 2024
At 1 January 2024 (restated) 235,887
Acquisitions 2.7 30,627
Accretion expense 3.2 4,511
Changes in estimates to provisions 1,408
Utilisation of provisions (757)
Effect of changes to discount rate (3,976)
Foreign exchange differences (7,276)
At 30 June 2024 (260,424)
Of which:
Current 1,718
Non-current 258,706
Total 260,424
Abandonment provisions primarily include:
· In the Netherlands, the Group's share of the estimated cost of
abandoning the producing Q10-A wells, decommissioning the associated
infrastructure, plugging and abandoning the currently suspended Q11-B well,
and removal and restoration of certain onshore pipelines and corresponding
land from historic assets. Abandonment of the producing wells and
infrastructure is expected to take place between five and eight years from the
balance sheet date, in 2026 for the Q11-B well and within one year for the
onshore pipelines and land restoration.
· In the UK Production segment, 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 SGP and restoration of the land upon which the plant is
constructed. Abandonment is expected to take place between five and fourteen
years from the balance sheet date, subject to production and commodity price
forecasts and level of use of the SGP by third parties.
· In Norway, plugging and abandonment of drilled wells on Ringhorne
and Balder, and removal of the Balder FPU and Ringhorne platform. Abandonment
is expected to take place in approximately 25 years' time.
· In the UK Storage segment, the re-brining of gas storage caverns
and decommissioning of gas storage plant assets. Abandonment is expected to
take place in approximately 20 years' time.
Abandonment provisions are initially estimated in nominal terms, based on
management's assessment of publicly available economic forecasts and
determined using inflation rates of 2.25% to 2.50% (2023: 2.0% to 2.5%) and a
discount rate of 2.73% to 4.14% (2023: 2.2% to 3.8%). The changes in estimates
to provisions arise primarily as a result of the increased inflation rate
assumed in certain regions.
The Group has in issue £69 million ($88 million) of surety bonds as at 30
June 2024 and 31 December 2023 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 final
decommissioning of the fields.
2.6 Joint arrangements and licence interests
As at the balance sheet date, the Group has the following interests in joint
arrangements 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.
Except where otherwise noted, the interest and status of licences is the same
as at the end of the prior period.
Field or licence Country Licence holder Licence type Status Interest at 30 June 2024
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 and Glenlivet)
P2411 and P1453(2) (Benriach) UK Kistos Energy Limited Exploration Non-operated 25%
P2594 (Cardhu) UK Kistos Energy Limited Exploration Non-operated 20%
P2604 (Roseisle) UK Kistos Energy Limited Exploration Non-operated 14%
PL001 Norway Kistos Energy (Norway) AS Production Non-operated 10%
PL027(4) Norway Kistos Energy (Norway) AS Production Non-operated 10%(5)
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) Acquired or awarded during the current period.
(3) Licence P1453 is split into the portion including and excluding the
Benriach area.
(4) Licence 027 comprises Balder and Ringhorne Øst fields. Kistos' share of
the Ringhorne Øst unit is 7.4%.
2.7 Acquisitions
On 23 April 2024, the Group acquired 100% of the share capital of EDF Energy
(Gas Storage) Limited (subsequently renamed Kistos Energy Storage Limited)
from EDF Energy (Thermal Generation) Limited for cash consideration of £25
million ($31.1 million) less closing working capital adjustments (the 'Gas
Storage Acquisition'). The main assets acquired in the transaction comprise
two gas storage facilities onshore in the UK, Hill Top Farm ('Hill Top') and
Hole House Farm ('Hole House') which has a total current working volume of up
to 21.2 million therms.
The acquisition was accounted for as an acquisition of a group of assets as
substantially all the fair value of the gross assets acquired was concentrated
in a group of similar identifiable net assets (and therefore the
'concentration test' provisions of IFRS 3 'Business Combinations' was met).
No goodwill or bargain purchase was recognised as the transaction was
accounted for as an asset acquisition and not a business combination. Directly
attributable acquisition-related costs were not capitalised as part of the
transaction as they were not considered to be material.
Section 3 Income statement
3.1 Earnings per share
6 months ended 6 months ended
30 June 2024
30 June 2023
(restated)
Consolidated loss/profit for the period, attributable to shareholders of the 14,503
Group ($'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 - 26,752
Weighted average number of ordinary shares and potential ordinary shares used 82,863,743 82,890,495
in calculating diluted earnings per share
Basic (loss)/earnings per share ($) (0.21) 0.18
Diluted (loss)/earnings per share ($) (0.21) 0.17
3.2 Net finance costs
$'000 Note 6 months ended 6 months ended
30 June 2024
30 June 2023
(restated)
Bank interest income 1,789 2,846
Interest on tax receivable 2,295 -
Other interest income 8 -
Total interest income 4,092 2,846
Bond interest (17,302) (1,911)
Other interest - (22)
Interest on tax payable (628) (1,680)
Surety bond costs (1,569) (485)
Total interest expenses (19,499) (4,098)
Accretion expense on abandonment provisions and other liabilities 2.5 (4,511) (2,453)
Accretion expense on lease liabilities (76) (57)
Remeasurement gain on Hybrid Bond 5.1 7,792 1,329
Amortisation of bond costs - (553)
Net foreign exchange (losses)/gains (14,942) 5,427
Total other net finance (costs)/income (11,737) 3,693
Total net finance (costs)/income (27,144) 2,441
Section 4 Working capital
4.1 Cash and cash equivalents
Cash and cash equivalents consist of cash at bank, short-term deposits and
restricted cash. Restricted cash includes deposits lodged for office leases,
employee withholding taxes in Norway, and cash lodged as letters of credit
under gas storage capacity arrangements. Financial covenants relating to
minimum liquidity balances are disclosed in note 5.1.1.
$'000 30 June 2024 31 December 2023
(restated)
Cash at bank and short-term deposits 69,950 214,789
Restricted cash 2,057 185
72,007 214,974
4.2 Trade and other receivables
$'000 30 June 2024 31 December 2023
(restated)
Trade receivables 4,158 9,142
Accrued income 10,849 9,819
Receivables due from joint operation partner 900 653
Other receivables and cash overcalls 5,771 1,996
Prepayments 4,772 6,916
VAT receivable 1,444 689
Total trade and other receivables 27,894 29,215
Accrued income represents amounts due in respect of hydrocarbon sales and gas
storage capacity revenue that had not been invoiced at the balance sheet date.
All hydrocarbon sales accrued income had been invoiced and collected in full
within one month of the corresponding reporting date. Certain amounts relating
to gas storage capacity revenue are contractually due to be collected in the
second quarter of 2025.
4.3 Trade payables and accruals
$'000 30 June 2024 31 December 2023
(restated)
Trade payables 4,423 6,822
Payables to joint operators 3,209 2,881
Accruals 27,445 34,774
Total trade payables and accruals 35,077 44,477
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, and amounts accrued by joint operators
but not yet billed. The carrying value of trade payables and other accrued
expenses are considered to be fair value given their short-term nature.
4.4 Other liabilities
$'000 30 June 2024 31 December 2023
(restated)
Bond interest payable 7,030 1,071
Salary and payroll-related liabilities 1,168 1,083
Lease liabilities 680 326
VAT payable 136 685
Overlift 3,256 1,671
Other 1,830 1,316
Other liabilities - current 14,100 6,152
Lease liabilities 5,695 678
Other liabilities - non-current 5,695 678
Lease liabilities include leasehold land and subterranean caverns acquired as
part of the Gas Storage Acquisition.
Section 5 Capital and debt
5.1 Bond debt
$'000 Total
At 1 January 2024 (restated) 237,936
Issue of new bonds via payment-in-kind interest 3,991
Interest expense 2,593
Remeasurement of Hybrid Bond (7,792)
Net foreign exchange gains and other movements 149
At 30 June 2024 236,877
Details of the bonds outstanding are as follows:
30 June 2024 31 December 2023 (restated)
Bond Issuer Denomination Nominal interest rate Maturity date Face value Carrying amount Face value Carrying amount
$'000 $'000 $'000 $'000
KENO01 Kistos Energy (Norway) AS USD 10.25%(1) November 2027 116,809 101,817 116,809 99,990
KENO02 Kistos Energy (Norway) AS USD 9.75%(2) September 2026 128,084 126,060 124,787 122,213
Hybrid Bond Kistos Energy (Norway) AS USD n/a March 2083(3) 45,000 9,000 45,000 15,733
Total 289,893 236,877 286,596 237,936
1. Interest payable wholly in kind via issuance of new bonds.
2. Interest payable partly in cash (4.5%) and partly in kind via issuance of
new bonds (5.25%).
3. Certain amounts of the Hybrid Bonds will be cancelled for nil consideration
should offload and sales thresholds related to the Jotun FPSO are not met,
starting 31 December 2024. In a situation where no crude oil has been lifted
and sold from the Jotun FPSO by 31 May 2025, all outstanding Hybrid Bonds will
be cancelled.
The Group has call options to redeem 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 Financial covenants
Under terms of the KENO01 and KENO02 bonds, Kistos Energy (Norway) AS (as
issuer) is required to maintain a minimum liquidity of $10 million until such
time as the Balder and Ringhorne fields have achieved 90 days of oil
production at an average rate of at least 75,000 barrels of oil per day
(gross). The issuer complied with the financial covenant at all times in the
current period.
Section 6 Tax
6.1 Tax credit or charge for period
$'000 6 months ended 6 months ended
30 June 2024 30 June 2023
(restated)
Current tax charge 7,269 13,730
Deferred tax credit (30,314) (33,514)
Total tax credit for the period (23,045) (19,784)
6.2 Current tax
6.2.1 Current tax receivable
The Group has a tax receivable of $122.4 million, $84.2 million of which is
due to be received in cash by the Group in December 2024 and $38.2 million is
due to be received in cash in December 2025. The current tax assets relate to
tax losses generated in Norway and accrue repayment interest from 1 January
2024 and 1 January 2025 respectively (the current statutory rate being 4.5%).
6.2.2 Current tax payable
The Group has current tax liabilities by segment as follows:
$'000 30 June 2024 31 December 2023
(restated)
Netherlands Production 53,478 55,090
Norway Production - -
UK Production 21,095 87,035
UK Storage 5,901 -
80,474 142,125
Current tax liabilities are anticipated to be settled within one year of the
balance sheet date, except €47 million ($50.4 million) relating the
Solidarity Contribution Tax (note 6.3) in the Netherlands Production segment,
for which the timing of settlement is uncertain.
Late or underpaid tax accrues interest at a rate of at least 6.25% in the UK
and 10% in the Netherlands. $0.6 million of late payment interest was charged
in the current period.
6.3 Uncertain tax positions
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 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 ($50.4 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 (excluding any accrued interest)
if it becomes payable. The Group expects to get further certainty around this
tax position in early 2025.
The Group filed its return in respect of the Solidarity Contribution Tax in
May 2024 (which was by the relevant deadline for submission), with its returns
stating a nil balance to be paid (for the reasons outlined above). As at the
date of approval of these interim financial statements, the Group had not
received any correspondence from the Belastingdienst (Dutch Tax Authority)
concerning the Solidarity Contribution Tax.
The Group is aware that Solidarity Contribution Tax is subject to legal
challenges on the grounds of, inter alia, the legality of its implementation
into Dutch law, nature of retrospective application and its specific
application to oil and gas producers in the Netherlands. Whilst the Group is
not directly involved in these challenges, it will closely monitor
developments and any outcome.
Should the Belastingdienst make 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%.
6.4 Changes to future tax rates
In March 2024, the UK Government announced an extension of the Energy Profits
Levy to 31 March 2029; however, this change was not substantively enacted. On
29 July 2024, the new UK Government announced that the rate of the Energy
Profits Levy will increase from 35% to 38% with effect from 1 November 2024.
The period that the levy applies is also being extended to 31 March 2030, with
the Energy Security Investment Mechanism ('ESIM') remaining in place
throughout that period. The government also announced its intention to abolish
the levy's main 29% investment allowance for qualifying expenditures incurred
on or after 1 November 2024, and also reduce the extent to which capital
allowance claims, including first year allowances, can be taken into account
when calculating profits subject to EPL. The impact of the proposed changes
announced on 29 July 2024 has not been included in the Interim period results
as they have not been enacted or substantively enacted at 30 June 2024. It
is expected that further details of the proposed changes will be announced on
30 October 2024 with substantive enactment thereafter.
Theses change, if substantively enacted, are not anticipated to have a
material impact on the Group's deferred taxation balances although the removal
of, and changes to, capital allowances may have a significant adverse impact
to the viability of future developments on the GLA.
Section 7 Other disclosures
7.1 Contingent liabilities
7.1.1 Contingent liabilities relating to Tulip Oil acquisition
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;
· €7.5 million payable upon confirmation by the Group of its
intention to retain ownership of the M10a and M11 licences;
· 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.
The €7.5 million contingent consideration relating to M10a and M11 was
derecognised in full in 2022 as the acquired entity had lost the rights to the
relevant licences as at 31 December 2022. The relevant licences were
re-awarded in 2023 following a successful appeal, but the Group is advised
that the vendor's ability to claim that contingent consideration has lapsed
and therefore the amount remains unrecognised on the balance sheet.
7.1.2 Decommissioning-related contingent liabilities
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 final
decommissioning of the fields.
7.1.3 Other contingent liabilities
Contingencies arising from uncertain tax positions are disclosed in note 6.3.
7.2 Subsequent events
7.2.1 Grant of share options
On 1 August 2024, the Company granted a total of 2,303,954 options over its
ordinary shares at an exercise price of £1.30 per ordinary share, of which
1,776,923 were granted to Executive Directors. The options vest in three equal
annual instalments commencing on the first anniversary of the date of grant,
subject to continued employment with no other performance conditions applying.
7.2.2 Balder Future project update
On 21 August 2024, Vår Energi (operator of the Group's interests in Norway),
announced that the target production start date for the Balder Future project
had been moved to the second quarter of 2025 (previously targeted to be by the
end of 2024). The confirmed delay to Balder Future production is a
non-adjusting event after the balance sheet date. The impact on incremental
capital spend required to accommodate this delay and a revised oil production
forecast is subject to review by the operator and Group. Any potential
impairment charge recognised in the second half of 2024 will depend on these
factors (in addition to the commodity prices prevailing at the time of
performing the test). It is also anticipated that the carrying value of the
Hybrid Bond will be reduced to zero (on the basis that no amount will become
payable) resulting in a gain of c.$9 million to be recognised in the income
statement in the second half of 2024.
Appendix A: Glossary
2C - contingent resources
2P - proved plus probable resources
Adjusted Production Costs - production operating costs per the income
statement (for Production segments only) less accounting movements in
inventory
Average realised sales price - revenue divided by hydrocarbon volumes sold
(converted to barrels of oil equivalent using the conversion factors in
Appendix C) 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
EPL - Energy Profits Levy
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
mmboe - million barrels of oil equivalent
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
SOFR - Secured Overnight Financing Rate
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
Unit opex - Adjusted Production Costs divided by hydrocarbon production
(converted to estimated barrels of oil equivalent using the conversion factors
in Appendix C) for the period
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 had completed on 1 January 2023. Management believe pro
forma information in this instance was useful as it allows meaningful
comparison of full year results across periods.
No pro forma information is provided in respect of the impact of the Gas
Storage Acquisition in 2024 as management consider the pre-acquisition trading
result is not representative of future operations because, inter alia, (a) the
pre-acquisition trading result in 2024 comprised primarily of the close-out of
positions placed by the previous operator in 2023; and (b) the pre-acquisition
trading arrangement resulted in a different presentation and accounting
treatment of trading gains and losses, which are not comparable to the current
activity controlled by management.
$'000 Revenue Adjusted EBITDA
Six months ended 30 June 2023
As reported 113,805 72,220
Pro forma adjustments for period 15,917 1,666
Pro forma results for six months ended 30 June 2023 129,722 73,886
B2: Net debt
Net debt is a measure that management believe is useful as it provides an
indicator of the Group's overall liquidity. It is defined as unrestricted 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 30 June 2024 31 December 2023
(restated)
Unrestricted cash and cash equivalents 4.1 69,950 214,789
Face value of bond debt 5.1 (289,893) (286,596)
Less: Hybrid Bond 5.1 45,000 45,000
Net debt (174,943) (26,807)
B3: Adjusted Production Costs and unit opex
Adjusted Production Costs (previously called Adjusted operating costs) are
production and operating costs attributable to the Group's three Production
segments, adjusted for accounting movements in inventory (being those
operating costs capitalised into liquids inventory as produced and expensed to
the income statement only when the related product is sold). Unit opex is
Adjusted Production Costs divided by barrels of oil equivalent produced for
the same period.
The definition of Adjusted Production Costs has changed from the prior period,
and now excludes operating costs from the UK Storage segment as such costs are
not incurred in the production of hydrocarbons for sale.
$'000 6 months ended 6 months ended
30 June 2024 30 June 2023
(restated)
Production and operating costs per income statement 54,601 35,984
Less: UK Storage segment operating costs (3,513) -
Accounting movements in inventory (5,643) (5,545)
Adjusted operating costs 45,445 30,439
Pro forma period adjustment - 11,042
Pro forma adjusted operating costs 45,445 41,481
Total production (kboe) 1,544 1,433
Pro forma period adjustment (kboe) - 226
Total pro forma production (kboe) 1,544 1,659
Unit opex $29/boe $25/boe
Appendix C: Conversion factors
37.3 scf of gas in 1 Nm(3) of gas
5,561 scf of gas in 1 boe
149.2 Nm(3) 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
28 tonnes of CO(2) equivalent in one tonne of natural gas (CH(4))
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: North Sea Transition Authority
(https://www.nstauthority.co.uk/media/5tib5x4n/nsta-gas-import-fact-sheet.pdf)
2 Conversion of natural gas (CH(4)) to CO2 equivalent is based on the IPCC's
AR5 global warming potential factor of 28.
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