REG - Kistos Holdings PLC - Interim Results & Hole House FID
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RNS Number : 3346A Kistos Holdings PLC 23 September 2025
THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION FOR THE PURPOSES OF ARTICLE 7 OF
REGULATION 2014/596/EU WHICH IS PART OF DOMESTIC UK LAW PURSUANT TO THE MARKET
ABUSE (AMENDMENT) (EU EXIT) REGULATIONS (SI 2019/310) (UK MAR). UPON THE
PUBLICATION OF THIS ANNOUNCEMENT, THIS INSIDE INFORMATION (AS DEFINED IN UK
MAR) IS NOW CONSIDERED TO BE IN THE PUBLIC DOMAIN.
23 September 2025
Kistos Holdings plc
("Kistos", the "Company", or the "Group")
Interim results for the six months to 30 June 2025 & FID of Hole House
Storage
Kistos (LSE: KIST), an independent energy company focused on generating value
across the upstream and midstream markets, is pleased to provide its interim
results for the period to 30 June 2025.
The first half of 2025 has been a period of significant and transformational
investment for Kistos. The Company has delivered on its commitment to achieve
first oil from the Balder FPSO in June, successfully meeting the key
operational milestone set out at the start of the year. As such, the Group
remains firmly on track to meet its full-year production guidance of 8,000 -
9,000 boepd.
The hybrid bond structure, designed from the outset to protect Kistos against
delays in the commissioning of the FPSO, has proved highly effective, ensuring
that financial outcomes were directly aligned with project delivery. These
achievements represent a pivotal shift, positioning the Group for substantial
increases in Revenue, EBITDA, and Cash Flow in the periods ahead.
In September 2025, the Group reached a Final Investment Decision to proceed
with the Hole House gas storage project. Supported by third-party financing on
attractive terms, the recommissioning will increase working capacity by 63%
and further strengthen the UK's energy resilience and flexibility.
Norway Operations
· Net production for H1 2025: 2,800 boepd (H1 2024: 2,800 boepd).
· A Final Investment Decision was taken on Balder Phase VI to
develop around 1.5 mmboe (net).
· Production efficiency at Balder FPU and Ringhorne Platform: 91%
(versus planned: 86%).
· Jotun FPSO departed Rosenberg-Worley yard in March, achieved
first oil in June, and started up the first of 14 Balder Future wells in July.
· Ramp-up of Balder Future wells was concluded in September 2025,
with peak production of approximately 9,000 boepd (net) and total area
production exceeding 11,000 boepd (net).
· COSL Pioneer rig began drilling six wells for Balder Phase V,
targeting 3.0 mmboe (net). First multi-lateral well completed by end of June
with First Oil expected in Q4 2025. Two new wells were also drilled from the
Ringhorne platform.
UK Operations
· Net production from Greater Laggan Area: 2,500 boepd (H1 2024:
3,400 boepd), in line with expectations.
· Victory first gas remains on schedule by end-2025, and increased
throughput at the Shetland Gas Plant is expected to deliver significant OPEX
savings for the Greater Laggan Area partners.
· At the Hole House gas storage site, a Final Investment Decision
was taken in September 2025 to proceed with recommissioning, underpinned by
favourable economics and third-party financing secured on attractive terms.
This decision will increase working capacity by 63%.
Netherlands Operations
· Q10-A production was significantly lower during the period, 900
boepd lower than in H1 2024 (2,200 boepd).
· Aside from natural decline, a planned shutdown of the
TAQA-operated P15-D platform overran for longer than expected (98 vs 35 days
planned), although this will be partially offset by flush production post
start-up in H2.
Corporate & Financial
· Capital investment of $70 million in Balder Future and Balder
Phase V, unlocking a high-value asset for the Company with low unit cost
~$5/boe.
· TotalEnergies' planned sale of its remaining 40% stake in West of
Shetlands assets to Prax Upstream Limited did not complete due to Prax's
parent company entering administration; assets remain with TotalEnergies.
· Total cash at period end: $104 million, including restricted
funds of $20 million.
· Adjusted net debt at period end: $86 million (30 June 2024: $89
million). See notes to the accounts for further details.
· Hybrid bonds linked to Jotun FPSO milestones were cancelled for
nil consideration; some bondholders exercised rights to acquire Kistos
warrants (exercisable at a price of 385 pence per share).
6 months ended 30 June 2025
H1 2025 H1 2024 Change %
Total production rate(1) boepd 6,200 8,400 -26%
Revenue $'000 87,903 113,328 -22%
Average realised oil price $/bbl 67 82 -18%
Average realised gas price $/boe 77 54 +43%
Adjusted EBITDA(2) $'000 23,673 48,585 -51%
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.
Andrew Austin, Executive Chairman of Kistos, commented:
"The Group is on track to meet our full-year production guidance of
8,000-9,000 boepd whilst upholding strong operational performance and
unlocking the full potential of our existing asset base to deliver long-term
value for shareholders.
The completion of Balder Future marks a pivotal event for Kistos. It
diversifies our production profile and rebalances our hydrocarbon mix, while
also releasing capital to support growth across other areas of the business.
Progress in Norway remains strong, with Balder Phase V achieving successful
completion of its first well and the positive investment decision on Balder
Phase VI both occurring during the first half of the year.
In the UK, we look forward to the start-up of the Victory field. This
development is anticipated to realise significant operating expenditure
savings for the GLA partners as throughput at the Shetland Gas Plant will
increase substantially. I am also pleased to confirm that the Group has taken
a Final Investment Decision to proceed with the Hole House gas storage
project. This milestone, supported by third-party financing on attractive
terms, reflects our commitment to enhancing the UK's energy resilience and
flexibility.
Kistos remains focused on disciplined execution, operational excellence, and
continues to seek out organic and inorganic growth opportunities. We are
committed to ensuring that any transaction we undertake, either in or outside
of the North Sea, offers meaningful near-term value creation for shareholders,
underpinned by a prudent risk profile. As we continue to evaluate
opportunities across the value chain, we remain centred on maintaining
financial strength and operational reliability."
Dr Richard Benmore, Non-Executive Director of Kistos with a Bachelors, Masters
and PhD in Geosciences and who has been involved in the energy industry for
more than 40 years, has read and approved the disclosure in this announcement.
The Company's internal estimates of resources contained in this announcement
were prepared in accordance with the Petroleum Resource Management System
guidelines endorsed by the Society of Petroleum Engineers, World Petroleum
Congress, American Association of Petroleum Geologists and Society of
Petroleum Evaluation Engineers.
Enquiries
Kistos Holdings plc via Hawthorn Advisors
Andrew Austin, Executive Chairman
Panmure Liberum (NOMAD, Joint Broker) Tel: 0207 886 2500
James Sinclair-Ford / Freddie Wooding
Mark Murphy / Sam Elder
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
https://www.kistosplc.com (https://www.kistosplc.com)
Kistos Holdings plc - 2025 Interim Report
Highlights
The first half of 2025 has been a period of significant and transformational
investment for Kistos. The Company delivered on its commitment to achieve
first oil from the Balder FPSO in June, successfully meeting the key
operational milestone set out at the start of the year. As such, the Group
remains firmly on track to meet its full-year production guidance of 8,000 -
9,000 boepd.
The hybrid bond structure, designed from the outset to protect Kistos against
delays in the commissioning of the FPSO, has proved highly effective, ensuring
that financial outcomes were directly aligned with project delivery. These
achievements represent a pivotal shift, positioning the Group for substantial
increases in revenue, EBITDA, and cash flow in the periods ahead.
In September 2025, the Group reached a Final Investment Decision to proceed
with the Hole House gas storage project. Supported by third-party financing on
attractive terms, the recommissioning will increase working capacity by 63%
and further strengthen the UK's energy resilience and flexibility.
In Norway, net production in the six months to 30 June 2025 was 2,800 boepd
(H1 2024: 2,800 boepd). During the period, two additional wells were drilled
from the Ringhorne platform, which supported production rates, whilst
cumulative production efficiency of the Balder FPU and Ringhorne Platform was
91% (versus planned 86%). The Jotun FPSO left the Rosenberg-Worley yard in
Stavanger during March, before undergoing sea trials and being towed to
location above the Balder field. The vessel achieved first oil during June and
started up the first of fourteen Balder Future wells during July. Ramp-up of
the Balder Future wells was concluded in September 2025, with peak production
of approximately 90,000 boepd (gross) and total area production exceeding
110,000 boepd (gross). A Final Investment Decision was taken on Balder Phase
VI to develop around 1.5 mmboe (net) and the COSL Pioneer semi-submersible rig
commenced its programme to drill and complete six wells relating to the Balder
Phase V project. By the end of June, the first Phase V multi-lateral well had
been successfully completed, and it is expected that first oil will be
achieved during Q4 2025, once the Jotun FPSO has sufficient ullage following
the start-up of Balder Future wells.
In the UK, net production of 2,500 boepd (H1 2024: 3,400 boepd) from the
Greater Laggan Area fields was in line with expectations. A prolonged outage
at the Ninian Central Platform delayed the ability to import gas for a routine
de-liquifying run, which impacted production during May. Victory first gas
remains on schedule for the end of 2025, which will utilise the Shetland Gas
Plant ("SGP") and other GLA infrastructure, substantially reducing Kistos'
future Unit OPEX.
In the Netherlands, Q10-A production was significantly lower during the period
than in H1 2024. Aside from natural decline, a planned shutdown of the
TAQA-operated P15-D platform overran for longer than expected (98 vs 35 days
planned), although this will be partially offset by flush production post
start-up in H2. A rigless intervention was attempted on the Q10-A04 Slochteren
zone, but was hindered by proppant in the tubing. Analysis of potential next
steps is underway. Pipeline abandonment works at Donkerbroek (onshore)
progressed towards completion.
In June 2024, TotalEnergies announced the sale of its remaining 40% operated
stake in the west of Shetlands assets to Prax Upstream Limited (formerly
Hurricane Energy Plc). In June 2025, it was announced that Prax's parent
company had gone into administration, resulting in this sale failing to
complete. Therefore, the assets remain in TotalEnergies ownership for the time
being and Kistos is confident that they will continue to be operated
responsibly and efficiently.
Unrestricted cash at the end of the period was $84 million (31 December 2024:
$143 million). The decrease was due to ongoing capital expenditure requirement
in Norway, and payments related to UK and Dutch tax liabilities. Adjusted net
debt at the end of the period was $86 million (31 December 2024: $52 million).
The hybrid bonds, which were only payable in full or in part if the Jotun
floating production storage and offloading vessel (FPSO) offloaded its first
cargo by 31 May 2025, were cancelled fully for nil consideration, as the first
offload occurred following the close of the period. Certain bondholders
exercised their rights to acquire warrants in Kistos. Unit opex for the period
increased to $42/boe (H1 2024: $29/boe) due to lower production in the
Netherlands and UK but is expected to fall significantly with First Oil from
Balder Future wells, which have a unit cost of ~$5/boe.
H1 2025 H1 2024 Change %
Average production rate(1,2) boepd 6,200 8,400 -26%
Revenue $'000 87,903 113,328 -22%
Average realised oil price $/bbl 67 82 -18%
Average realised gas price $/boe 77 54 +43%
Adjusted EBITDA(3) $'000 23,673 48,585 -51%
1. 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.
2. 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.
3. 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, total Balder area production is expected to increase materially
throughout H2 2025, as all fourteen Balder future wells are brought on stream
through the Jotun FPSO. Towards the end of the year, and depending on well
performance and vessel ullage, it is expected that the two Balder Phase V
wells will also come onstream, further aiding the production rates. The Balder
FPU is expected to remain steady, other than natural decline of wells,
following the addition of two new Ringhorne platform wells during H1 2025. On
the Ringhorne platform, drilling is ongoing into what will be known as the
RHE-F well, which should come onstream by the end of 2025. Capital expenditure
will be significantly lower during the second half of 2025 following the
completion of refurbishment works on the Jotun FPSO, with approximately $45
million remaining to be spent. Capital expenditure for the period is
anticipated to be primarily made up of ongoing drilling for the Balder Phase V
project whilst operating expenditure will increase in line with the addition
of the Jotun FPSO to the field infrastructure. The Balder Phase V project,
which received a positive final investment decision ("FID") in October 2024,
is targeting more than 30 mmboe (gross) from six wells, with attractive
breakeven metrics of approximately $30/boe. Balder Phase VI achieved FID
during June 2025 and consists of a multi-lateral well tied back to the Jotun
FPSO via the installation of a new subsea template and flowline. Balder Phase
VI is targeting approximately 15 mmboe (gross), with start-up expected by the
end of 2026 and payback is expected in less than one year. In the meantime,
the tax rebate in respect of 2024, to be repaid to Kistos in December 2025, is
expected to be approximately $74 million, excluding accrued interest.
In the UK, at the Greater Laggan Area, we are focused on the start-up of the
third-party Victory gas field, with first gas expected during H2 2025. It is
anticipated to realise significant OPEX savings for the GLA owners as
throughput at the Shetland Gas Plant will increase significantly.
In the Netherlands, flush production from Q10-A is expected to partially
offset the impact of the extended P15-D shutdown in H1. Further optimisation
efforts will continue, including evaluating the feasibility of additional
interventions on Q10-A04. Completion of pipeline abandonment works at
Donkerbroek is expected during H2 2025.
Kistos exited 2024 with 2P reserves of 24.4 mmboe. Production in H1 2025 was
1.1 mmboe, and the sanctioning of Balder Phase VI plus some other minor
adjustments resulted in 2P reserves at 30 June of 24.7 mmboe. 2C contingent
resources were estimated to be 56.4 mmboe at the end of the period. Production
guidance for full year 2025 is reaffirmed in the 8,000 - 9,000 boepd range.
At Kistos' gas storage assets, work continued through the half year to
finalise the programme and economics for a return to service of the Hole
House. A Final Investment Decision was made in September 2025 to proceed with
recommissioning, underpinned by favourable economics and third-party financing
secured on attractive terms. The project is expected to deliver a 63% increase
in working capacity.
Chairman's Statement
I am pleased to report Kistos' interim results for the six months to 30 June
2025. Adjusted EBITDA for the period was $24 million, and total cash balances,
including restricted funds, stood at $104 million. This follows significant
investment activity, primarily in Norway, where $70 million of capital
expenditure was deployed to complete the Balder Future project and initiate
Balder Phase V.
The conclusion of Balder Future marks a pivotal milestone for Kistos. It
signals our transition from a gas-weighted company to a more balanced oil and
gas producer and unlocks capital to support growth across the wider portfolio.
Having completed four acquisitions in four years, we continue to evaluate a
pipeline of business development opportunities in and outside of the North
Sea. Alongside this, we are actively pursuing organic growth, as demonstrated
by the final investment decision on Balder Phase VI during the period.
In Norway, Balder Phase V is progressing well. The first well was completed in
H1, and the rig is now drilling the remaining five wells. Together with Vår
Energi, we were pleased to announce the FID on Balder Phase VI in June. This
development will add a new multi-lateral well and subsea infrastructure,
targeting approximately 1.5 mmboe (net), with first oil expected by year-end
2026.
In the UK, we continue to anticipate first gas from Victory in H2 2025. This
tie-back to the Shetland Gas Plant will materially enhance the economics of
our production in the Greater Laggan Area. I am also pleased to confirm that
the Group has taken a Final Investment Decision to proceed with the Hole House
gas storage project. This milestone, supported by third-party financing on
attractive terms, reflects our commitment to enhancing the UK's energy
resilience and flexibility.
In the Netherlands, Q10-A production was impacted by natural decline and an
extended shutdown of the TAQA-operated P15-D platform. While this affected
output during the period, flush production following restart is expected to
partially offset the impact in H2.
On behalf of our shareholders, I am proud to report continued progress in
building a resilient and forward-looking energy business-one that supports
reliable supply and contributes to the broader energy transition.
The first half of 2025 has been a period of consolidation and focus. Following
several years of M&A activity, we have successfully integrated our
business units and strengthened our strategic capabilities. This disciplined
approach positions us well for the next phase of growth, both organically and
through selective acquisitions. We remain confident in our long-term strategy
and committed to delivering value for shareholders while playing a
constructive role in shaping the future of energy. Throughout the period, we
maintained our commitment to high standards of health, safety and
environmental performance across all our operations.
Andrew Austin
23 September 2025
Financial Review
Unaudited results for the 6 months ending 30 June 2025
30 June 2025 30 June 2024(6)
Production rate(1) boepd 6,200 8,400
Total production(1)
UK kboe 445 627
NL kboe 160 409
Norway kboe 514 508
kboe 1,119 1,544
Revenue
Liquids $'000 36,138 61,983
Natural gas $'000 44,601 49,433
Gas trade $'000 7,164 1,912
87,903 113,328
Average realised sales price(2)
Liquids $/boe 67 82
Natural gas - UK $/boe 76 53
Natural gas - NL $/boe 83 54
72 65
Unit opex(3) $/boe 42 29
Adjusted EBITDA(4) $'000 23,673 48,585
Basic earnings per share $ 0.41 (0.21)
Capital expenditure $'000 (69,819) (83,164)
Adjusted net (debt)/cash(5) $'000 (86,038) (88,638)
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. 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 B2.
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 B1.
6. 2024 results for six months ended 30 June 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.
Key Financials:
· Revenue: $87.9 million (H1 2024: $113.3 million), reflecting
lower production rates and oil prices, partially offset by higher realised gas
prices in the UK and Netherlands.
· Adjusted EBITDA: $23.7 million (H1 2024: $48.6 million), with
the decrease driven by lower volumes and oil pricing.
· Unit opex: $42/boe (H1 2024: $29/boe), reflecting lower
production rates against broadly flat operating costs.
· Capital Expenditure: $69.8 million, almost entirely allocated to
the Balder Future project in Norway.
· Adjusted Net Debt: $86 million at period end (30 June 2024: $89
million), reflecting ongoing investment and tax payments.
· Cash and Restricted Funds: $104 million, of which $20 million is
currently restricted.
Operating Costs and Opex:
Unit opex for the period (which excludes non-cash accounting movements in
inventory and cost of sales from the UK Storage segment) increased to $42/boe
(H1 2024: $29/boe), reflecting the impact of decreased production rates in the
Netherlands and UK against broadly flat operating costs. Unit opex is expected
to fall materially with First Oil from Balder Future wells, which have a unit
cost of ~$5/boe.
Adjusted EBITDA:
Adjusted EBITDA decreased to $23.7 million, primarily due to lower production
volumes in the Netherlands and UK and lower oil price in Norway.
Capital Expenditure:
Cash capital expenditure in the first half of 2025 was $69.8 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 primarily incurred on ongoing drilling for the Balder Phase V project,
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 2024 Norwegian tax losses (primarily generated by
capital expenditure in that year) is anticipated to be approximately NOK 746
million ($74.0 million), not including accrued interest, to be received in
December 2025. The tax receivable generated by losses incurred in the first
half of 2025 is estimated to be NOK 414 million ($41.1 million).
Tax:
The net accounting tax charge for the period was $5.5 million, primarily
driven by deferred tax movements arising from foreign exchange gain on Nordic
bonds. This was partially offset by a tax credit on tax losses generated in
Norway, along with deferred tax movements in the UK and Netherlands.
The net current tax charge for the period, (which only reflects tax due or
receivable on profits or losses made in the period) was $1.6 million (H1:
2024: tax charge $7.3 million). This reflects the statutory headline rates of
78%, 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 during the period totalled $23.8 million (H1 2024: $73
million), primarily relating to the settlement of UK tax liabilities on 2023
profits, as well as tax payments in the Netherlands covering both 2022 and
2023 profits.
As a result of significant capital expenditure incurred on the Balder Future
project, tax losses generated in Norway during 2024 have triggered a tax
rebate. This rebate is expected to amount to $74 million (746 million NOK),
plus interest, and is scheduled to be received in December 2025.
The current tax liability at 30 June 2025 was $31.0 million (31 December 2024:
$93.6 million). The decrease from prior period reflects a reassessment of
Solidarity Contribution Tax liability. Based on current expectations, if the
liability becomes payable, it is not expected to be settled within twelve
months. Additionally, it doesn't meet the definition of deferred tax under IAS
12. As a result, the liability of €47.0 million (pre discount) has been
reclassified from current - where it was presented in the prior period-to
non-current tax liability in the current period (see note 6.2.3).
Debt and Other Finance Income:
The face value of bond debt on 30 June 2025 was $264 million, comprising
USD-denominated bonds issued by Kistos' Norwegian subsidiary. Hybrid Bond debt
with a face value of $45 million, linked to production milestones on the Jotun
FPSO, was fully cancelled on 28 May 2025. In exchange, bondholders were
allocated and received a specified number of warrants over Kistos shares,
exercisable at a price of 385 pence per share. The unrealised foreign exchange
gain associated with bonds primarily arises from differences between the
Group's presentation currency and that of its Norwegian subsidiary, which are
the main drivers of the non-cash component of other finance income.
Risks and Outlook:
Principal risks and uncertainties remain unchanged since the last annual
report. The Group remains on track to meet its full-year production guidance
of 8,000-9,000 boepd. The transformational investments made in H1 2025 are
expected to deliver substantial financial and operational benefits going
forward.
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 2024 Annual Report
dated 10 April 2025. 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 Risk Management" on page 24 of the Kistos Holdings plc 2024 Annual
Report dated 10 April 2025, 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.
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
0.01 kg/boe in H1 2025.
Across the Q10-A platform in the Netherlands, as well as our non-operated
offshore interests in the GLA and on the Norwegian Continental Shelf (NCS),
the Group's Scope 1 and Scope 2 emissions intensity ratios remains below the
North Sea average (estimated by the North Sea Transition Authority (NSTA)(1)
to be 24 kg CO(2)/boe for 2023). They are also estimated to be significantly
lower than the average CO(2) emissions intensity associated with the import of
liquefied natural gas (LNG), which the NSTA estimates(1) to be on average four
times higher than the North Sea average.
Our UK gas storage assets do not consume gas on site, but they do emit small
quantities of emissions associated with natural gas venting as part of the
safety systems for process equipment. During the period, 283 tonnes of CO(2)
equivalent natural gas were vented and 5.7 tonnes of CO(2) equivalent consumed
in diesel.
In the 6 months to 30 June 2025, our share of total Scope 1 and 2 emissions
were estimated at 24,600 tonnes of CO(2) equivalent (CO(2)e). No flaring was
undertaken in the current period, apart from that noted for our gas storage
site.
The Group remains committed to maintaining safe working environment. We are
pleased to report that no Lost Time Injuries were recorded during the
reporting period in our operated asset and gas storage business.
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
$'000 Note 6 months ended 6 months ended
30 June 2025 30 June 2024
Revenue 2.1 87,903 113,328
Other operating income 1,263 196
Cost of sales (55,301) (54,601)
Gross profit 33,865 58,923
Exploration and development expenses (597) (635)
Abandonment expenses (1,937) (1,794)
General and administrative expenses (9,081) (8,894)
Depreciation, amortisation and impairment 2.3, 2.4 (39,730) (60,743)
Operating loss (17,480) (13,143)
Interest income 3.2 2,608 4,092
Interest expenses 3.2 (17,023) (19,499)
Other finance income 3.2 30,780 7,792
Other finance costs 3.2 (5,743) (19,529)
Net finance income/(costs) 10,622 (27,144)
Loss before tax (6,858) (40,287)
Tax (charge)/credit 6.1 (5,479) 23,045
Loss for the period (12,337) (17,242)
Basic loss per share ($) 3.1 (0.15) (0.21)
Diluted loss per share ($) 3.1 (0.15) (0.21)
Condensed consolidated statement of other comprehensive income
$'000 6 months ended 6 months ended
30 June 2025 30 June 2024
Loss for the period (12,337) (17,242)
Items that may be reclassified to profit or loss:
Foreign currency translation differences 6,392 (2,443)
Total comprehensive loss for the period (5,945) (19,685)
Condensed consolidated balance sheet
$'000 Note 30 June 2025 31 December 2024
Non-current assets
Goodwill 2.4 55,393 49,215
Intangible assets 2.4 33,652 30,272
Property, plant and equipment 2.3 585,729 489,508
Non-current tax receivable 6.2.1 41,126 -
Deferred tax assets 2,312 1,885
Investment in associates 1,066 1,066
Other long-term receivables 201 176
719,479 572,122
Current assets
Inventories 18,082 18,436
Trade and other receivables 4.2 17,956 20,602
Current tax receivable 6.2.1 74,036 65,450
Restricted funds 4.1 19,767 29,385
Cash and cash equivalents 4.1 83,883 113,753
213,724 247,626
Total assets 933,203 819,748
Equity
Share capital and share premium 9,979 9,979
Other equity 5,557 5,557
Other reserves 78,610 71,311
Accumulated losses (62,425) (50,088)
Total equity 31,721 36,759
Non-current liabilities
Abandonment provision 2.5 287,754 251,426
Bond debt 5.1 251,901 245,243
Deferred tax liabilities 199,497 134,389
Non-current tax liability 6.2.3 50,291 -
Other non-current liabilities 4.4 8,994 7,703
798,437 638,761
Current liabilities
Trade payables and accruals 4.3 43,659 32,180
Other current liabilities 4.4 24,803 14,952
Current tax payable 6.2.2 30,999 93,604
Abandonment provision 2.5 3,584 3,492
103,045 144,228
Total liabilities 901,482 782,989
Total equity and liabilities 933,203 819,748
Condensed consolidated statement of changes in equity
$'000 Share capital and share premium Other equity Other reserves Accumulated losses Total equity
At 1 January 2024 9,979 3,897 74,714 1,911 90,501
Loss for the period - - - (51,999) (51,999)
Other comprehensive loss - - (3,956) - (3,956)
Total comprehensive loss for the period - - (3,956) - (3,956)
Share-based payments - - 553 - 553
Issue of warrants - 1,660 - - 1,660
At 31 December 2024 9,979 5,557 71,311 (50,088) 36,759
Loss for the period - - - (12,337) (12,337)
Other comprehensive income - - 6,392 - 6,392
Total comprehensive loss for the period - - 6,392 (12,337) (5,945)
Share-based payments - - 907 - 907
At 30 June 2025 9,979 5,557 78,610 (62,425) 31,721
Condensed consolidated cash flow statement
$'000 Note 6 months ended 6 months ended
30 June 2025 30 June 2024
Cash flows from operating activities:
Loss for the period (12,337) (17,242)
Tax charge/(credit) 6.1 5,479 (23,045)
Net finance (income)/costs 3.2 (10,622) 27,144
Depreciation, amortisation and impairment 2.3, 2.4 39,730 60,743
Share-based payment expense 1,398 28
Income tax paid (23,846) (73,011)
Interest income received 1,048 1,789
Abandonment costs paid 2.5 (269) (757)
Decrease in trade and other receivables 12,254 3,543
Increase/(decrease) in trade and other payables 7,008 (11,518)
Decrease in inventories 2,700 4,975
Net cash flow from operating activities 22,543 (27,351)
Cash flows from investing activities:
Payments to acquire tangible and intangible fixed assets (69,819) (83,164)
Consideration paid for Gas Storage Acquisition, net of cash acquired 2.7 - (22,070)
Release from restricted funds 11,804 -
Net cash flow from investing activities (58,015) (105,234)
Cash flows from financing activities:
Interest paid (2,881) (3,447)
Lease repayments and other financing cash flows (1,332) (1,760)
Net cash flow from financing activities (4,213) (5,207)
Decrease in cash and cash equivalents (39,685) (137,792)
Cash and cash equivalents at beginning of period 113,753 214,974
Effects of foreign exchange rate changes 9,815 (5,175)
Cash and cash equivalents at end of period 83,883 72,007
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 2025 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 2024 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. 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 23 September 2025.
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 2026 (the going concern period) by
preparing a base case forecast and various combined downside sensitivities.
The base case assumed the following:
· 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, considering the
first oil date from the Jotun FPSO in June 2025.
· 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 $74 million (746 million NOK) received in
December 2025.
· Obligations under Decommissioning Security Agreements (DSAs) for
the GLA fields are satisfied at least in part by the issuance of surety bonds
during the period covered by the going concern assessment.
· Commodity prices based on forward curves prevailing at the date
of assessment (being an average of 82p/therm, €32/MWh and $67/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;
· adverse movement in foreign exchange rates; and
· an assumption that the 2026 DSA for the GLA fields, estimated to
be in excess of £73 million, had to be to be partially covered in cash.
The outcome of applying one or more of these reasonably plausible downside
scenarios against the base case supported the going concern conclusion.
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 Interim Financial Statements have been prepared in accordance with the
accounting policies adopted in the Group's annual financial statements for the
year ended 31 December 2024.
There are no accounting pronouncement which have become effective from 1
January 2025 that have significant impact on the Group's interim condensed
consolidated financial statements.
Other minor change has been made to the presentation of certain line items in
the comparative financial statements and the notes:
· On the consolidated income statement, foreign exchange and other
net finance costs is now presented in two lines 'other finance income' and
'other finance costs' (previously within 'foreign exchange movements and other
net finance costs').
· On the consolidated income statement, depreciation and
amortisation and impairment are now combined in one line 'depreciation,
amortisation and impairment'.
· On the consolidated income statement, 'Production and operating
costs' has been renamed as 'Cost of sales' and 'Exploration and development
expenses' are now on the same line.
· On the consolidated income statement a gross profit line has
been added.
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 2024. The only
exceptions are the estimate of income tax liabilities which is determined in
this half-yearly report using the estimated average annual effective income
tax rate applied to the pre-tax income of the interim period.
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.
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 2025:
· The hybrid bonds were fully cancelled on 28 May 2025. In
exchange, bondholders were allocated and received a specified number of
warrants over Kistos shares, exercisable at a price of 385 pence per share.
· The Group has increased its existing credit facility from $20
million to $30 million.
· Cash outflows of $23.8 million in respect of tax liabilities.
Section 2 Oil and gas operations
2.1 Revenue
$'000
6 months ended 30 June 2025
Netherlands Norway UK Total
Sales of liquids - 31,279 4,859 36,138
Sales of natural gas 12,535 - 32,066 44,601
Gas storage - - 7,164 7,164
Revenue from contracts with customers 12,535 31,279 44,089 87,903
$'000
6 months ended 30 June 2024
Netherlands Norway UK Total
Sales of liquids - 54,544 7,439 61,983
Sales of natural gas 21,039 - 28,394 49,433
Gas storage - - 1,912 1,912
Revenue from contracts with customers 21,039 54,544 37,745 113,328
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 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 2025 30 June 2024
Adjusted EBITDA by segment:
Netherlands 242 12,855
Norway 10,885 26,401
UK 13,540 11,759
Corporate (994) (2,430)
Group Adjusted EBITDA 23,673 48,585
Development expenses (25) (154)
Share-based payment expense (1,398) (29)
Depreciation, amortisation and impairment 2.3, 2.4 (39,730) (60,743)
Transaction costs - (802)
Operating loss (17,480) (13,143)
Net finance income/(costs) 3.2 10,622 (27,144)
Loss before tax (6,858) (40,287)
2.3 Property, plant and equipment
$'000 Freehold land Oil and gas production assets Gas storage facilities and other Total
Cost
At 1 January 2025 2,093 815,453 71,561 889,107
Additions - 69,754 - 69,754
Disposals - - (536) (536)
Foreign exchange differences 214 113,415 7,128 120,757
At 30 June 2025 2,307 998,622 78,153 1,079,082
Accumulated depreciation and impairment
At 1 January 2025 - (391,566) (8,033) (399,599)
Depreciation charge for period - (39,225) (395) (39,620)
Foreign exchange differences and other movements - (53,715) (419) (54,134)
At 30 June 2025 - (484,506) (8,847) (493,353)
Net book value at 31 December 2024 2,093 423,887 63,528 489,508
Net book value at 30 June 2025 2,307 514,116 69,306 585,729
2.4 Intangible assets and goodwill
$'000 Goodwill Exploration and evaluation assets Other Total
Cost
At 1 January 2025 52,969 124,460 1,017 178,446
Acquisitions (note 2.7) - - - -
Additions - 264 221 485
Foreign exchange differences and other movements 6,545 14,596 112 21,253
At 30 June 2025 59,514 139,320 1,350 200,184
Accumulated amortisation and impairment
At 1 January 2025 (3,754) (94,504) (701) (98,959)
Amortisation and impairment charge for the period - (19) (91) (110)
Foreign exchange differences and other movements (367) (11,621) (82) (12,070)
At 30 June 2025 (4,121) (106,144) (874) (111,139)
Net book value at 31 December 2024 49,215 29,956 316 79,487
Net book value at 30 June 2025 55,393 33,176 476 89,045
Exploration and evaluation assets include the exploration licence portfolio
acquired as part of the GLA Acquisition and exploration prospects in Norway.
2.5 Abandonment provision
$'000 Note 6 months ended
30 June 2025
At 1 January 2025 254,918
Accretion expense 3.2 5,518
Changes in estimates to provisions -
Utilisation of provisions (269)
Effect of changes to discount rate -
Foreign exchange differences 31,171
At 30 June 2025 291,338
Of which:
Current 3,584
Non-current 287,754
Total 291,338
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 infrastructure is expected to
take place between three and six years from the balance sheet date, in 2028
for the Q10-A and Q11-B wells. Onshore pipelines and land restoration are
nearly done, will be completed before year-end.
· 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 2.0% to 2.50% and a discount rate of 2.6%
to 5.1%.
The obligation for the decommissioning in respect of 2025 was £62.9 million
(2024 H1: £69 million), which the Group satisfied via issuing £45 million of
surety bonds and an amount of £17.9 million letters of credit to cover its
obligations under Decommissioning Security Agreements (DSA). 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 2025
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 Netherlands Kistos NL2 B.V. Exploration Operated 60%
Q13b Netherlands Kistos NL2 B.V. Exploration Operated 60%
Q14 Netherlands Kistos NL2 B.V. Exploration Operated 60%
P911, P1159, P1195, P1453(2) and P1678 UK Kistos Energy Limited Production Non-operated 20%
(Laggan, Tormore, Edradour and Glenlivet)
P2411 and P1453 (Benriach) UK Kistos Energy Limited Exploration Non-operated 25%
P2683 (Ballechin) UK Kistos Energy Limited Exploration Non-operated 33%
PL001 Norway Kistos Energy (Norway) AS Production Non-operated 10%
PL027(3) Norway Kistos Energy (Norway) AS Production Non-operated 10%
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) Licence P1453 is split into the portion including and excluding the
Benriach area.
(3)Licence 027 comprises Balder and Ringhorne Øst fields. Kistos' share of
the Ringhorne Øst unit is 7.4%.
2.7 Acquisitions
In April 2024, the Group completed the acquisition of EDF Energy (Gas Storage)
Limited (subsequently renamed Kistos Energy Storage Limited) which was
accounted for as an acquisition of group of assets.
Section 3 Income statement
3.1 Earnings per share
6 months ended 6 months ended
30 June 2025
30 June 2024
Consolidated loss for the period, attributable to shareholders of the 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 122,562 -
Weighted average number of ordinary shares and potential ordinary shares used 52,986,305 82,863,743
in calculating diluted earnings per share
Basic loss per share ($) (0.15) (0.21)
Diluted loss per share ($) (0.15) (0.21)
3.2 Net finance income/(costs)
$'000 Note 6 months ended 6 months ended
30 June 2025
30 June 2024
Bank interest income 1,048 1,789
Interest on tax receivable 1,560 2,295
Other interest income - 8
Total interest income 2,608 4,092
Bond interest (15,171) (17,302)
Other interest (106) -
Interest on tax payable (795) (628)
Surety bond costs (951) (1,569)
Total interest expenses (17,023) (19,499)
Accretion expense on abandonment provisions and other liabilities 2.5 (5,518) (4,511)
Accretion expense on lease liabilities (225) (76)
Remeasurement gain on Hybrid Bond 5.1 730 7,792
Net foreign exchange (losses)/gains 30,050 (14,942)
Total other net finance income/(costs) 25,037 (11,737)
Total net finance income/(costs) 10,622 (27,144)
Section 4 Working capital
4.1 Cash and cash equivalents and restricted funds
As at 30 June 2025, the cash and cash equivalents balance was $83.9 million
(2024: $113.8 million).
Financial covenants relating to minimum liquidity balances are disclosed in
note 5.1.1.
As at 30 June 2025, restricted funds consisted of $19.8 million (2024: $29.4
million) held in a separate bank account for the purpose of providing security
against letters of credit/bonds issued in respect of decommissioning
liabilities and surety bonds. Also, it includes cash lodged as letters of
credit for gas storage capacity arrangements, deposit lodged for office leases
and employee withholding tax in Norway.
4.2 Trade and other receivables
$'000 30 June 2025 31 December 2024
Trade receivables 1,049 349
Accrued income 6,400 11,861
Receivables due from joint operation partner 1,060 858
Other receivables and cash overcalls 2,872 1,242
Prepayments 4,761 4,939
VAT receivable 1,814 1,353
Total trade and other receivables 17,956 20,602
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 2026.
4.3 Trade payables and accruals
$'000 30 June 2025 31 December 2024
Trade payables 9,487 4,427
Payables to joint operators 1,407 1,359
Accruals 32,765 26,394
Total trade payables and accruals 43,659 32,180
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 2025 31 December 2024
Bond interest payable 8,214 1,153
Salary and payroll-related liabilities 1,466 1,294
Lease liabilities 846 970
VAT payable 1,649 223
Overlift 3,603 6,971
Credit facility 3,182 -
Other 5,843 4,341
Other liabilities - current 24,803 14,952
Long-term employee benefit liabilities 820 328
Lease liabilities 8,174 7,375
Other liabilities - non-current 8,994 7,703
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 2025 245,243
Issue of new bonds via payment-in-kind interest 3,354
Interest expense 2,406
Remeasurement of Hybrid Bond (730)
Net foreign exchange gains and other movements 1,628
At 30 June 2025 251,901
Details of the bonds outstanding are as follows:
30 June 2025 31 December 2024
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 128,782 117,809 $128,782 115,131
KENO02 Kistos Energy (Norway) AS USD 9.75%(2) September 2026 134,942 134,092 $131,468 129,382
Hybrid Bond Kistos Energy (Norway) AS USD n/a March 2083(3) 45,000 - 45,000 730
Total 251,901 245,243
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. All outstanding hybrid bonds have been cancelled due to no crude oil being
lifted from the Jotun FPSO by 31 May 2025.
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
The KENO01 and KENO02 bonds have minimum liquidity requirements of the issuer,
being $10 million minimum liquidity, applicable from
1 January 2024 until first oil from the Jotun
FPSO defined as the date on which Balder Ringhorne Licences have achieved 90
days of production of oil with an average oil production per day of 75
kbbl.
Section 6 Tax
6.1 Tax credit or charge for period
$'000 6 months ended 6 months ended
30 June 2025 30 June 2024
Current tax charge 1,595 7,269
Deferred tax charge/(credit) 3,884 (30,314)
Total tax charge/(credit) for the period 5,479 (23,045)
6.2 Current tax
6.2.1 Current tax receivable
The Group has a tax receivable of $115 million wholly relating to tax losses
incurred in Norway, $74 million of which is due to be received in cash by the
Group in December 2025 and $41 million is due to be received in cash in
December 2026 unless it is utilised to reduce the tax payable that could
result from profit in that year. The current tax assets accrue repayment
interest from 1 January 2025 and 1 January 2026 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 2025 31 December 2024
Netherlands 361 59,803
United Kingdom 30,638 33,801
30,999 93,604
Current tax liabilities are anticipated to be settled within one year of the
balance sheet date.
Late or underpaid tax accrues interest at a rate of at least 5.75% in the UK.
$0.8 million of late payment interest was charged in the current period.
6.2.3 Non-current tax payable
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 there is a reasonable basis to conclude that Kistos NL2
B.V. is out of scope, as less than 75% of its turnover under Dutch GAAP was
derived from the specified activities. This position is supported by external
advice and reflected in the Group's Solidarity Tax Contribution tax return,
filed in May 2024, which reported a nil liability.
The Group is aware that the legality of the Solidarity Contribution Tax,
including its retrospective application, is subject to ongoing legal
challenges by other parties and certain EU member states. However, given the
uncertainty surrounding the interpretation and the fact that the tax return
has not been audited by Dutch tax authority, the Group applied IFRIC 23,
'Uncertainty over Income Tax Treatments'.
Accordingly, a provision of €47 million (pre discount) has been recognised,
representing the most likely amount of the charge (excluding any accrued
interest) if it becomes payable.
As the liability is not expected to be settled within twelve months and does
not meet the definition of deferred tax liability under IAS 12, it has been
reclassified from current - where it was presented in the prior year - to
non-current tax liability. In accordance with IFRS measurement principles, the
liability has been discounted using the Dutch risk-free rate, based on the
yield of The Netherlands three-year government bond.
Should the Dutch tax authority (Belastingdienst) issue an adverse ruling and
determine that the Group acted with gross negligence or wilful misconduct in
submitting a nil return, material penalties and interest could apply. Late
payment interest would accrue from 31 May 2024 at the applicate rate of 10%
per annum.
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;
· 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 status of the projects and
developments above, the contingent considerations above remain 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.
7.2 Subsequent events
7.2.1 Change of operator in GLA
During 2024, it was announced that TotalEnergies E&P UK Ltd (40% and
operator of GLA JV) had agreed to sell its entire stake and operatorship to
the Prax Group. The deal was anticipated to complete in the second quarter of
2025. However, the transaction was halted due to Prax's parent company
entering liquidation proceedings in June 2025.
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: Adjusted net (debt)/cash
Adjusted net (debt)/cash is a measure that management believes is useful as it
provides an indicator of the Group's overall liquidity. It is defined
as cash and cash equivalent and restricted funds and current tax receivables
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 2025 30 June 2024 31 December 2024
Cash and cash equivalents and restricted funds 4.1 103,650 72,007 143,138
Current tax receivables 6.2.1 74,036 84,248 65,450
Less: face value of bond debt (excluding Hybrid Bond) 5.1 (263,724) (244,893) (260,251)
Net debt (86,038) (88,638) (51,663)
B2: Adjusted Cost of Sales and unit opex
Adjusted Cost of Sales (previously called Adjusted operating costs) represents
the production and operating expenses attributable to the Group's three
Production segments. These costs are adjusted to reflect inventory accounting
movements specifically, operating costs capitalised into liquids inventory
when produced and only expensed to the income statement upon sale of the
related product. Additionally, operating costs from the UK Storage segment are
excluded, as they do not relate to the production of hydrocarbons for sale.
Unit opex is Adjusted Cost of Sales divided by barrels of oil equivalent
produced for the same period.
$'000 6 months ended 6 months ended
30 June 2025 30 June 2024
Cost of sales per income statement 55,301 54,601
Less: UK Storage segment cost of sales (8,207) (3,513)
Accounting movements in inventory (254) (5,643)
Adjusted cost of sales 46,840 45,445
Total production (kboe) 1,119 1,544
Unit opex $42/boe $29/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
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