REG - Star Energy Group - Final Results
Tue 07:00
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RNS Number : 5892G Star Energy Group PLC 29 April 2025
29 April 2025
Star Energy Group plc (AIM: STAR)
("Star Energy" or "the Company" or "the Group")
Full year results for the year ended 31 December 2024
Commenting today, Ross Glover, Chief Executive Officer, said:
"I am very pleased to be presenting my first annual results as Chief Executive
Officer of Star Energy. Our strategic aim is to be a profitable energy
business generating strong cashflows from our oil and gas assets whilst
progressing growth opportunities in the geothermal sector. By focusing on
maximising profitability from our oil and gas activities, we ensure long-term
sustainability and can successfully navigate a volatile oil price environment,
which is increasingly important in today's uncertain geopolitical climate. We
have maintained strong production across our fields and made good progress in
reducing costs, with substantial general and administrative savings projected
for 2025.
Investing in our producing assets provides a robust financial foundation for
future growth, and I am confident that geothermal energy presents a
significant growth opportunity in both the UK and Europe. Successful project
development will create material incremental asset value and can deliver
strong returns for shareholders. We recognise that it will take time to bring
our geothermal projects to production and are committed to rigorously
assessing project commerciality in order to allocate capital based on strict
criteria for achievement of milestones and creation of value. This approach
will enable us to build a portfolio of profitable projects over time."
Financial Performance
2024 2023
£m £m
Revenues 43.7 49.5
Net debt* 7.5 1.6
Adjusted EBITDA* 11.1 16.1
Operating cash flow before working capital movements 8.8 15.0
Loss after tax (12.6) (5.5)
Cash and cash equivalents (excluding restricted cash) 4.7 3.9
Underlying operating profit* 5.9 9.1
* Adjusted EBITDA, Net Debt (borrowings less cash and cash equivalents
excluding capitalised fees) and Underlying Operating Profit are used by the
Group, alongside IFRS measures for both internal performance analysis and to
help shareholders, lenders and other users of the Annual Report to better
understand the Group's performance in the period in comparison to previous
periods and to industry peers
Corporate & Financial Highlights
· Successfully secured a €25 million financing facility provided
by Kommunalkredit Austria AG which, while primarily supporting the development
of our geothermal energy sector, also enables continued investment in the oil
and gas business utilising existing cash flows
· Cash at 31 December 2024 was £4.7 million, excluding restricted
cash, and Star Energy had drawn £12.2 million under its loan facility.
Restricted cash was £4.3 million and relates to the cash backing of
performance bonds for licence commitments of the Company's Croatian subsidiary
relating to the Sječe and Pčelić exploration licences
· Increased our stake in our Croatian subsidiary post year end,
from 51% to 71%, allowing us to control the development of this initiative
until appropriate value inflection points are achieved
· Exchanged contracts for the sale of non-core land for £6.3
million in November 2024 with proceeds received in April 2025
· Hedging in place for 400bbl/d for H1 2025 and H2 2025 with swaps
at an average price of $79.8/bbl and $73.0/bbl, respectively
· Energy Profits Levy of £1.0 million paid in February 2025 based
on the taxable profits for the year ended 31 December 2023. The Company
estimates a charge of £2.1 million for 2024
Operational Highlights
· Net production, in line with guidance averaging 1,989 boepd in
2024 (2023: 2,100), with uptime across the portfolio remaining strong over
the year
· Continued to optimise oil production from our existing wells
through selective investment in short cycle developments which deliver quick
payback
· DeGolyer & MacNaughton updated CPR values 2P NPV10 at $188
million (2023: $235 million). The decrease in reserves value is due to a
development project moving out of the reserves category due to project
prioritisation
· Work has begun on the Singleton gas-to-wire project which will
deliver c.74 boe/d, utilising gas which is currently being flared. The
project, which satisfies the regulatory requirements for the facility, now has
planning consent and a secured grid connection. Procurement for long lead
items is underway, with a first export of electricity from the site expected
late 2025
· Ernestinovo licence commitments have been fulfilled and the
acquisition of magnetotelluric data across the Sjece and Pcelic geothermal
licence blocks in Croatia is complete, with the incorporation of this data
into the geological models underway. Work is ongoing on the technical
analysis to rank the optimal sequencing of their commercial development
· Seismic data was acquired and analysed for the Salisbury NHS
Foundation Trust project, and pre-applications have been submitted for
planning and permitting for both Salisbury and the Wythenshawe Hospital
projects
Outlook
· We anticipate net production of c.2,000 boepd and operating costs
of c.$40/boe (assuming an average exchange rate of £1:$1.27) in 2025
· 2025 forecast capital expenditure is c.£10.0 million. This
includes £5.8 million on the Singleton gas-to-wire project which is forecast
to come online in late 2025 with production of 74 boe/d. Star Energy also
plans to invest £1.7 million on quick returning incremental projects and the
balance on regulatory improvements, site resilience and projects to reduce
operating costs going forward
· Holybourne sale proceeds of £6.3 million will be used to repay
Facility A of our Kommunalkredit loan which is due on 30 June 2025
· Good progress on G&A costs reduction expected to generate
savings of c.£1.5 million in 2025
· Data analysis continuing to further derisk our Croatian portfolio
· Seeking strategic partnerships in the UK to advance our pipeline
A results presentation will be available later today
at https://www.starenergygroupplc.com/investors/reports-publications-presentations/
Marie Dransfield, Technical Director of Star Energy Group plc, and a qualified
person as defined in the Guidance Note for Mining, Oil and Gas Companies, June
2009 as updated 21 July 2019, of the London Stock Exchange, has reviewed and
approved the technical information contained in this announcement. Mrs
Dransfield has 19 years' oil and gas exploration and production experience.
For further information please contact:
Star Energy Group plc Tel: +44 (0) 207 993 (mailto:info@lifesafetechnologies.com) 9899
Ross Glover, Chief Executive Officer
Frances Ward, Chief Financial Officer
Zeus (Nominated Adviser & Broker) Tel: +44 (0) 203 829 5000
Antonio Bossi, Alexandra Campbell-Harris (Investment Banking)
Simon Johnson (Corporate Broking)
Vigo Consulting Tel: +44 (0) 207 597 5970
Patrick d'Ancona, Finlay Thomson, Kendall Hill
Chairman's statement
I am pleased with the progress we have made on our strategic aims during the
year despite an increasingly challenging political and regulatory environment.
Our focus remains on being a responsible operator of our oil and gas assets,
managing these for maximum value and rightsizing to maintain profitability,
whilst continuing to contribute to the delivery of the UK's domestic energy
security.
At a time of increasing international uncertainties, where the value of energy
security is important, 100% of our production comes from the UK onshore and is
consumed in the UK. We focus on maintaining consistent volumes of production
and investing our capital to create value for shareholders now and over the
longer term. We are keen to capitalise on our undoubted skills in onshore oil
and gas operations to develop growth opportunities as these arise in
geothermal power and heating, both in the UK and Croatia.
Our long experience of successful and environmentally responsible onshore oil
and gas development and operation, together with a substantial skillset in
this area is readily transferable to geothermal. We have established expertise
in navigating the regulatory and planning environment and have very
experienced commercial, subsurface and operating teams. We calibrate our
initiatives to match the readiness of our counterparties and customers. Our
expertise has been supplemented through the acquisition of A14 Energy in 2023,
where the Croatian team provide significant in-country expertise. We have the
technical and operational capability to de-risk projects, creating natural
monetisation points that offer flexibility to retain or farm down assets for
early value realisation.
We have strengthened our balance sheet through securing a €25 million debt
facility with Kommunalkredit AG which, while primarily funding geothermal
growth, also allows us to reinvest cashflows in our oil and gas assets. The
sale of a non-core asset for £6.3 million which completed in 2025, was an
important step in realising value from our existing assets. However, improving
our resilience in an uncertain commodity price environment is critical and we
have already made good progress on this, realising significant savings in our
cost base as we go into 2025.
Generating strong cashflows from our existing operations is important in
creating value for shareholders. We have continued to operate in a safe and
environmentally friendly manner and achieved a strong safety performance for
the year. The safety of our staff and that of the communities we work in is of
paramount importance and will always be front and centre as we look to
streamline our operations and drive down costs. Our existing operations
provide a solid platform for maximising profits in our conventional oil
business and provide the professional and capital resources as new energy
opportunities materialise.
In a UK context, the decarbonisation of heat utilising the geothermal resource
beneath our feet can deliver a sustainable, low carbon and on demand energy
source. Approximately half of energy consumed in the UK is ultimately used in
the creation of heat. The development of a geothermal sector would provide
baseload heat. It could help make Britain the clean energy superpower promoted
by the government and boost economic growth whilst helping the country achieve
its legally binding net zero targets. With our extensive UK onshore expertise,
transferable skills and subsurface database, we are in a strong position to
deliver low carbon heat energy for the country provided that the government is
able to use its convening and co-ordinating powers to help deliver executable
projects in a timely fashion.
In Croatia, we have advanced our geothermal projects with further data
acquisition and interpretation across all three licences. Geothermal activity
in the country is increasing rapidly, and Croatia is emerging as a European
hotspot for the sector. A supportive regulatory regime and government backing
provide a solid foundation for the development of our existing licences and
further expansion. Growing investor interest underlines the potential, and our
increased stake in the Croatian subsidiary post year end, from 51% to 71%,
allows us to control the development of this initiative until appropriate
value inflection points are achieved.
In 2024, we appointed Ross Glover as CEO, who brings a depth of experience
in both oil and gas and renewable energy development. Ross has been with Star
since 2017 and was previously COO. We thank the previous CEO, Chris
Hopkinson, for his contribution to the development of the Company and we wish
him all the best for the future.
On behalf of the Board, I would like to thank everyone in the business for
their commitment and professionalism. It is the combination of a proven track
record of strong operational performance, resilience and adaptability that
keep the business moving forward.
Outlook
Recent times have amply demonstrated that energy is a strategic resource and
the basic building block for a modern economy looking for growth. The current
geopolitical climate and its impact on oil prices reinforces the importance of
resilience in a volatile commodity price environment. As the largest onshore
oil and gas company in the UK, Star has an important role to play. The energy
transition is underway, and we are at the forefront of the challenges and
opportunities that this evolution brings. However, the approach must be
managed wisely as hydrocarbons currently continue to provide the world with
some 80% of our daily energy supply (much of it imported into the UK). The
Company will accordingly continue to maximise its own cashflows from its
existing energy portfolio. We will invest in our conventional business to
maintain production levels. It is important to recognise the continuing role
of fossil fuels in providing for UK energy needs during the transition to a
low carbon economy and developing indigenous, locally produced resources is a
critical part of the UK's future energy security. We continue to play our part
in delivering that.
Operating review
We continue to operate in a safe and environmentally sensitive manner, which
is a fundamental principle guiding all our activities and decisions. Our focus
on maximising profitability from our oil and gas activities is crucial for
long-term sustainability and enables us to successfully navigate a volatile
oil price environment. We plan to capitalise on government backing, an
investor-friendly regulatory framework, and increased investor interest in
Croatia, presenting a unique opportunity for expansion and progression of our
geothermal projects in this region. In the UK, we are advancing geothermal
energy to take advantage of the government's renewable energy aspirations,
proceeding cautiously until a clearer investment framework is established.
Oil and gas
The Company's focus is on optimising the net profitability of the fields from
which it produces. In this context, predictability of production (across its
mature portfolio of operations) is also important. Well uptime remained strong
across the year with net production for the year averaging 1,989 boepd (2023:
2,100 boepd). Good results from a rolling programme of well optimisation and
stimulation activities yielded additional production at a number of sites.
However, as expected, we saw a reduction in production from our Albury field
(c. 80 boe/d) due to a decline in gas pressure resulting in the cessation of
gas exports.
We continue to offset decline rates through the execution of low cost
incremental production projects with short pay-back times, and have increased
the efficiency of our well service operations thereby achieving better uptimes
across our sites. We have made progress in reducing operating costs in certain
areas, from £24.1 million in 2023 to £22.3 million, however, more work needs
to be done and this will be a focus as we go forward. We are still seeing the
impact of the regulatory burden but are working with regulators to address
those costs and/or duplication of effort which do not contribute to our high
standards as an environmentally responsible operator. We upgraded pipelines
and the processing centre at our Gainsborough site which will result in lower
operating costs going forward. However, a step-change in operating costs is
dependent on optimising the operational portfolio, including full field
abandonment at less productive sites. Work has started on this and, following
the full impairment of our shale assets in 2023, we have started to
rationalise our portfolio of exploration licences, relinquishing early-stage
exploration and shale licences whilst retaining core exploration acreage
adjacent to our existing operations in the East Midlands. Five wells have been
abandoned at our non-operated Doe Green and Irlam sites, with site restoration
work planned for 2025. Alongside this, we have re-organised and simplified our
operating licence structure. This re-organisation will lead to reduced costs
and a lower administrative burden going forward.
We have also made good headway in reducing our G&A costs with a target to
achieve annual savings of c.£1.5 million with effect from 2025. We will
continue to maximise cashflows from our oil and gas business and secure an
income stream that is resilient in a volatile commodity price environment.
Work has begun on the Singleton gas-to-wire project which will deliver c.74
boe/d, utilising gas which is currently being flared. The project, which
satisfies the regulatory requirements for the facility, now has planning
consent and a secured grid connection. Procurement for long lead items is
underway, with a first export of electricity from the site expected in late
2025. We have permitted projects at Glentworth (200boepd), Corringham
(100boepd) and Bletchingley (6MW gas-to-wire), however, progress on these is
subject to finding a farm-in partner.
Geothermal Energy
We see exciting opportunities for growth in our geothermal business, both in
the UK and Croatia. The International Energy Agency's report on geothermal
energy in December 2024 recognised the huge potential for geothermal energy
and concluded that, if geothermal can follow in the footsteps of innovation
success stories such as solar PV, wind, EVs and batteries, it can become a
cornerstone of tomorrow's electricity and heat systems as a dispatchable and
clean source of energy.
Croatia
In Croatia, there is now significant activity in the geothermal sector, with
over 100MW of geothermal power capacity projected to come online in 2028.
Confirming its commitment to the sector, the Croatian government is drilling
four geothermal exploration wells in 2025. This, along with a clear regulatory
framework, has seen the emergence of the Pannonian Basin, in which our
licences are located, as a key European geothermal hotspot. Our increased
stake in A14 Energy Limited provides us with greater flexibility in our plans
to accelerate the development of our Croatian assets and, when appropriate
value inflection points have been achieved to introduce other partners. The
increased interest does not expose us to material additional costs in the
short to medium term due to the existing carry arrangements.
We have fulfilled our exploration obligations on our Ernestinovo licence and
have established the exploitation field on the licence. A field development
plan is under preparation and we expect to submit this shortly. We have
completed the acquisition of magnetotelluric data across our Sjece and Pcelic
licences. This data will delineate the reservoir and allow us to update our
estimates of reservoir size. All our Croatian licences are in areas where
substantial offset data sets are available from previous conventional oil and
gas drilling activities. Our technical teams are at an advanced stage of
consolidating all existing and new data for each of our three licences. This
analysis will allow us to bring the development plans for each licence up to
date and will inform our next steps and the optimal sequencing for the
licences' commercial development. Preliminary conclusions point to good
prospects within our Croatian portfolio, with high temperatures recorded in
existing wells comparable with other Croatian geothermal reservoirs.
UK
In the UK, we have been successful in obtaining grant funding to progress our
NHS projects. We continue to work in partnership with the Salisbury and
Manchester NHS hospital trusts to decarbonise their operations and provide a
reliable long-term source of heat. We are also pleased to be working with
Bring Energy to explore the further integration of geothermal energy into
Southampton's city-centre heat network where we will leverage our geothermal
expertise to assess the potential for supplying heat to the existing network
as well as exploring the development of a new geothermal supplied heat network
to serve the northern part of the city.
The UK has legally binding net zero by 2050 targets, with interim carbon
budgets set under the Climate Change Act 2008. Heating accounts for c.37% of
all UK emissions and decarbonisation of the public sector is a key element of
this. To date, UK government policy of decarbonising heat has had an emphasis
on electrification, however, electrification alone is not a sufficient
solution given electricity generation capacity is significantly less than will
be required, and generating the additional capacity will involve material
upgrades to the national grid. The next 12 months will be an important
opportunity for the UK Government to demonstrate its commitment towards the
decarbonisation of heat and, in particular, geothermal energy as an important
tool in achieving its net zero ambitions. Geothermal energy can provide a
solution to the UK's heat decarbonisation goals and we are well placed to take
advantage of this significant opportunity.
Seismic data acquisition was completed in September 2024 for the Salisbury NHS
Foundation Trust project. Processing and interpretation of the data acquired
was completed by year end. We are preparing a planning application for
submission in 2025.
In Manchester, at the Wythenshawe Hospital project, reprocessing and
interpretation of legacy data is complete. Further seismic data will be
acquired in Q4 2025, with the survey design largely completed.
As disclosed in note 6, the Stoke-on-Trent geothermal project in its original
form is no longer progressing and we have therefore impaired the development
costs of £4.3 million. As a result of its cancellation, £2.3 million of the
related contingent consideration provision was released in the period.
Financial Review
Our focus for 2024 has been on strengthening our balance sheet, improving the
resilience of our oil and gas business in the light of volatile commodity
prices and positioning the Group for growth in the geothermal sector. We
secured a €25 million debt facility (provided by Kommunalkredit Austria AG
(Kommunalkredit)) which, while primarily supporting the development of our
geothermal energy business, also enables continued investment in the oil and
gas business utilising existing cash flows. We also exchanged contracts for
the sale of non-core land and the proceeds of £6.3 million were received in
April 2025. We commenced a cost reduction initiative in our G&A costs and
forecast material savings for 2025.
Production for the year averaged 1,989 boepd (2023: 2,100 boepd), in line
with our production guidance. Brent oil prices remained stable until September
when they came under pressure as a result of geopolitical tensions and
concerns about demand. The average Brent price was $81/bbl in 2024 compared to
$83/bbl in 2023. Sterling strengthened during the year with average
GBP/USD rates of £1:$1.28 in 2024 compared to £1:$1.25 in 2023, negatively
impacting our revenues which are mainly denominated in USD.
Revenues for the year were £43.7 million compared to £49.5 million in 2023,
a reduction of £5.8 million reflecting lower commodity prices, particularly
for gas and electricity, foreign exchange movements and lower volumes. The
Group generated a net oil price hedging gain of £0.7 million for the year
compared to a loss of £0.03 million in 2023. Other cost of sales decreased
from £24.1 million in 2023 to £22.3 million in 2024 as reductions from cost
savings, lower production and processing fewer third-party barrels more than
offset inflationary increases. Underlying operating costs (which exclude third
party oil but include costs relating to leases capitalised under IFRS 16) were
£32.8 ($42.0) per boe for the year (2023: £32.4 ($40.3) per boe).
Realised Price/Cost Per Barrel
2024 2023
$ $
Realised price per barrel 77.5 79.9
Administrative expenses per BOE 13.3 12.0
Other operating costs (underlying) 32.0 30.0
Well services 6.8 7.2
Transportation and storage 3.2 3.1
Adjusted EBITDA was £11.1 million (2023: £16.1 million) and the underlying
operating profit was £5.9 million (2023: £9.1 million), with the variance
resulting primarily from a reduction in revenues.
Adjusted EBITDA
Reconciliation of (loss)/profit before tax to Adjusted EBITDA
2024 2023
£m £m
(Loss)/profit before tax (4.5) 2.8
Net finance costs 4.8 4.4
Depletion, depreciation & amortisation* 6.5 8.3
Impairment of development costs 4.3 -
Exploration and evaluation assets impaired 1.9 0.5
Goodwill impairment - 0.1
Changes in fair value of contingent consideration (2.3) -
EBITDA 10.7 16.1
Lease rentals capitalised under IFRS 16 (1.9) (1.8)
Other expenses 2.0 -
Share-based payment charge 0.2 0.7
Unrealised (gain)/loss on hedges (0.4) 0.5
Redundancy costs 0.5 0.1
Acquisition costs - 0.5
Adjusted EBITDA 11.1 16.1
Related to oil and gas business segment 15.1 19.1
Related to Geothermal business segment (4.0) (3.0)
* Includes depreciation charge recorded in administrative expenses
Underlying operating profit
Reconciliation of operating (loss)/profit to underlying operating profit
2024 2023
£m £m
Operating (loss)/profit (1.9) 7.2
Other expenses 2.0 -
Lease rentals capitalised under IFRS 16 (1.9) (1.8)
Depreciation charge of right-of-use assets 1.2 1.3
Share-based payment charge 0.2 0.7
Impairment of development costs 4.3 -
Exploration and evaluation assets impaired 1.9 0.5
Goodwill impairment - 0.1
Unrealised (gain)/loss on hedges (0.4) 0.5
Redundancy costs 0.5 0.1
Acquisition costs - 0.5
Underlying operating profit 5.9 9.1
Net Debt
31 December 2024 31 December 2023
£m £m
Debt (nominal value excluding capitalised expenses) (12.2) (5.5)
Cash and cash equivalents (excluding restricted cash) 4.7 3.9
Net debt (7.5) (1.6)
Restricted cash was £4.3 million (€5.2 million) which provides cash backing
for the performance guarantees issued in relation to geothermal licence
commitments in Croatia.
Income Statement
The Group recognised revenues of £43.7 million for the year (2023: £49.5
million). Oil revenue was £42.0 million compared to £44.8 million in 2023,
reflecting lower prices and volumes and a stronger USD to GBP exchange rate.
The average pre-hedge realised price for the year was $76.9/bbl (2023:
$79.0/bbl). Gas revenues reduced to £0.2 million (2023: £ 1.9 million) due
to lower gas prices and the permanent shut-in of gas-to-grid production at our
Albury site. Electricity revenues declined by £0.6 million, primarily due to
lower prices. Revenues relating to the sale of third-party oil also declined
from £1.2 million to £0.3 million with the reduction relating mainly to
lower volumes being processed in the year.
A gain of £0.7 million was recognised on oil hedges during the year (2023:
loss of £0.03 million) with 201,400 bbls of fixed oil price contracts at an
average price of $78.6/bbl (2023: 120,000 bbls at an average price of
$88.1/bbl).
Cost of sales for the year were £28.8 million (2023: £32.3 million)
including DD&A of £6.5 million (2023: £8.2 million), and other costs of
sales of £22.3 million (2023: £24.1 million). Other costs of sales decreased
by £1.8 million compared to 2023 mainly due to reduction in staff costs,
lower workover and maintenance activity following the investment in our fields
in 2023 and a reduction in third-party volumes being processed. The DD&A
charge has decreased by £1.7 million mainly due to an increase in the proven
and probable reserves as at 1 January 2024 as compared to 1 January 2023 and
due to lower production volumes in the year.
Adjusted EBITDA in the year was £11.1 million (2023: £16.1 million). The
gross profit for the year was £14.9 million (2023: £17.1 million).
Administrative costs remained largely consistent with prior year at £7.4
million (2023: £7.3 million). The increase in costs in the year due to
redundancy payments, lower allocation to capital projects and inflationary
increases was partially offset by a reduction in legal and professional costs,
lower share-based payment charges and savings from cost reduction measures.
Research and non-capitalised development costs were £2.0 million (2023: £2.0
million), of which £1.6 million (2023: £1.6 million) related to our
operations in Croatia, primarily for the re-entry and testing of a well on the
Ernestinovo licence. These are early-stage costs which do not meet the
criteria for capitalisation as development costs under IAS 38 Intangible
Assets. The remainder of the costs mainly related to UK geothermal business
development costs and expenditure on the NHS Trust geothermal projects, net of
any grants received.
An impairment of development costs of £4.3 million (2023: £nil million) was
recognised related to the Stoke-on-Trent geothermal project following the
decision by SSE to change the focus of the project towards an 'Energy from
Waste' project. The majority of the Stoke-on-Trent development costs arose as
part of the GT Energy UK Limited acquisition. However, a significant portion
of the consideration was based on achieving various milestones on that project
and as a result of its cancellation, £2.3 million (2023: £nil million) of
this contingent consideration provision was released.
Other expenses of £2.0 million (2023: £nil million) were incurred in the
year in connection with preparing our Holybourne Oil Terminal site for sale.
We exchanged contracts for the sale of the site in November 2024 with
completion in April 2025.
Exploration and evaluation assets impaired of £1.9 million mainly represent
costs incurred on PEDL 235 (Godley Bridge) where we decided not to renew that
licence (2023: £0.5 million impairment of costs relating to our oil and gas
assets where there was no further development prospect and trailing costs on
previously impaired unconventional licences).
Net finance costs were £4.8 million (2023: £4.4 million) including interest
and fees on borrowings of £1.1 million (2023: £1.2 million) and costs
related to the performance guarantees issued in relation to licence
commitments in Croatia of £0.4 million (2023: £0.1 million). Finance costs
also included the unwinding of the discount on the decommissioning provision
of £2.5 million (2023: £2.6 million) and interest charge on lease
liabilities of £0.7 million (2023: £0.7 million). Net foreign exchange
losses during the year were £0.1 million (2023: gain of £0.2 million) mainly
arising from our Croatian operations.
A net tax charge of £8.1 million (2023: £8.3 million) was recognised during
the year, mainly due to the reduction in the deferred tax asset relating to
tax losses reflecting the decrease in the oil and gas reserves forecast (£6.1
million) and a current tax charge arising as a result of the Energy Profits
Levy (£2.0 million).
Cash Flow
Net cash generated from operating activities for the year was £2.3 million
(2023: £17.2 million). The reduction was primarily due to the decrease in
cash inflows from revenue of £6.6 million, an increase in the cash outflows
from operating costs, administrative expenses, including non-recurring legal
and professional costs, and research and non-capitalised development costs of
£8.6 million, partially offset by reduction in abandonment spend of £0.5
million.
The Group invested £5.7 million across its asset base during the year (2023:
£8.5 million) primarily comprising of upgrades and a pipeline replacement at
our Gainsborough site, optimisation projects across our portfolio to offset
declines, rationalisation and decommissioning at our Holybourne site and
general improvements across our fields.
The Group completed the refinancing of its borrowing facility during the year
and secured a €25.0 million facility with Kommunalkredit Austria AG.
Drawdowns were made primarily to repay the remaining balance under the
reserves based lending (RBL) facility with BMO Capital Markets (BMO) of £5.5
million (€ 6.7 million), to provide cash backing for the performance
guarantees issued in relation to licence commitments in Croatia of £4.3
million (€5.2 million) and to fund geothermal activity during the year. The
amount drawn at the end of the year was £12.2 million (€14.8 million).
Net debt at the end of the year was £7.5 million (2023: £1.6 million). In
addition, the Group held £4.3 million (€5.2 million) of restricted cash in
relation to the Croatian performance bonds.
Facility arrangement and other fees were £0.6 million and we paid loan
interest of £0.5 million (2023: £0.8 million).
Balance Sheet
Net assets reduced by £12.3 million to £42.6 million at 31 December 2024
(2023: £54.9 million), primarily due to a reduction in the intangible assets,
property, plant and equipment, deferred tax asset and trade and other
receivables and an increase in borrowings (net of restricted cash) and
corporation tax payable, partially offset by a reduction in provisions and
trade and other payables.
Intangible assets reduced by £6.1 million due to the recognition of
impairment charges of £4.3 million relating to the Stoke-on-Trent geothermal
project and the impairment of exploration costs of £1.9 million primarily
relating to the Godley Bridge licence as explained above.
Property, plant and equipment reduced by £3.3 million during the year to
£70.7 million. The value of decommissioning assets reduced by £2.8 million
as a result of management's reassessment of the decommissioning provision.
Capital expenditure incurred in the year was £4.8 million and we recognised a
DD&A charge of £5.3 million.
The provision for decommissioning costs decreased by £1.5 million (2023:
£0.4 million) mainly as a result of abandonment activity undertaken during
the year (£1.1 million), a reassessment of the remaining provision, primarily
due to a change in the discount rate (£2.9 million) and the annual unwinding
of the discount on the provision (£2.5 million). The provision for contingent
consideration reduced by £2.3 million following the cancellation of the
Stoke-on-Trent project as explained above.
Trade and other payables reduced by £4.2 million as a result of timing of
activity on capital and abandonment projects. In addition, the balance at the
end of the previous year included accruals in relation to costs associated
with refinancing, well re-entry activity on the Ernestinovo licence in Croatia
and a liability related to the award of the Sječe and Pčelić Croatian
geothermal exploration licences. No similar balances were included in the
accruals and other creditor balance at the end of the current year. Trade and
other receivables reduced by £0.7 million mainly due to the decrease in
receivables from joint venture partners.
The deferred tax asset reduced by £6.1 million from £37.2 million at 31
December 2023 to £31.1 million at 31 December 2024 mainly due to a change in
forecast utilisation of available tax losses.
The Group recognised a current tax liability of £3.1 million at 31 December
2024 relating to the Energy Profits Levy charge for the years ended 2023 and
2024 (2023: £1.1 million).
The derivative asset of £0.4 million (2023: £nil) represents the fair values
of the open commodity price hedges provided by counterparties with whom the
trades have been entered into.
Going Concern
The Group continues to closely monitor and manage its liquidity. Cash flow
forecasts for the Group are prepared on a monthly basis based on, inter alia,
the Group's production and expenditure forecasts, management's best estimate
of future oil prices and foreign exchange rates and the Group's available loan
facility. Sensitivities are run to reflect different scenarios including, but
not limited to, possible reductions in commodity prices, fluctuations in
exchange rates and reductions in forecast oil production rates.
The current geopolitical climate and the impact of an increase in trade
tariffs on the global economy has reduced crude oil prices in the first
quarter of 2025, with volatility in oil prices and foreign exchange rates
likely to continue whilst countries seek to negotiate trade agreements with
the US.
The focus of the Group in 2024 has been to strengthen our balance sheet and
improve our resilience to oil price volatility. We have generated strong
operating cashflows in 2024 as a result of stable production and a continued
effort to minimise operating costs. We have also carried out a reorganisation
resulting in a material reduction in general and administrative costs going
into 2025. The €25 million finance facility agreed with Kommunakkredit, and
the sale of non-core land with the proceeds of £6.3 million being received in
April 2025, further improves our liquidity position.
However, the ability of the Group to operate as a going concern is dependent
upon the continued availability of future cash flows and the availability of
the monies drawn under its loan facility, which is dependent on the Group not
breaching the facility's covenants. To mitigate these risks, the Group
benefits from its hedging policy with 146,200 barrels hedged for 2025 using
swaps at an average price of $75/bbl.
The Group's base case cash flow forecast was run with average oil prices of
$65/bbl for the remainder of 2025 and $70/bbl for 2026, foreign exchange rates
of an average $1.31/£1 for the remainder of 2025 and $1.28/£1 for 2026. In
this base case scenario, our forecasts show that the Group will have
sufficient liquidity as well as sufficient financial headroom to meet the
applicable financial covenants for the 12 months from the date of approval of
the financial statements.
Management has also prepared a "severe but plausible" downside case, which
reflects the possible impact of global economic uncertainties resulting in the
oil price dropping to $55/bbl in Q2 2025 before recovering to $58/bbl in Q3
and Q4 2025, and to an average of $62/bbl in 2026. In this downside case
management has assumed foreign exchange rates of an average $1.33/£1 for the
remainder of 2025 and $1.33/£1 for 2026. Our downside case also includes a
reduction in production of 5% throughout the going concern period. In the
event of a downside scenario, management has the ability to drawdown further
under the loan facility as well as to take mitigating actions including
delaying capital expenditure and reducing costs, in order to maintain
liquidity and to remain within the Group's financial covenants over the
remaining facility period, should such actions be necessary. All such
mitigating actions are within management's control. In this downside scenario
including mitigating actions, our forecast shows that the Group will have
sufficient financial liquidity as well as sufficient headroom to meet its
financial covenants for the 12 months from the date of approval of the
financial statements. Management remain focused on maintaining a strong
balance sheet and funding to support our strategy.
Based on the analysis above, the Directors have a reasonable expectation that
the Group has adequate resources to continue as a going concern for at least
the next twelve months from the date of the approval of the Group financial
statements and have concluded it is appropriate to adopt the going concern
basis of accounting in the preparation of the financial statements.
Frances Ward
Chief Financial Officer
Non-IFRS Measures
The Group uses non-IFRS measures of performance that are not specifically
defined under IFRS or other generally accepted accounting principles. The
non-IFRS measures include net debt, adjusted EBITDA and underlying operating
profit.
These non-IFRS measures are used by the Group, alongside IFRS measures, for
both internal performance analysis and to help shareholders, lenders and other
users of the Annual Report to better understand the Group's performance in the
period in comparison to previous periods and to industry peers.
Net debt is defined as borrowings excluding capitalised fees less cash and
cash equivalents and does not include the Group's lease liabilities or
restricted cash.
Adjusted EBITDA and underlying operating profit includes adjustments in
relation to non-cash items such as share-based payment charges and unrealised
gain/ loss on hedges.
Lease costs for the period which have been capitalised under IFRS 16 have been
added to underlying operating costs and deducted in the calculation of
adjusted EBITDA.
CONSOLIDATED INCOME STATEMENT
FOR THE YEAR ENDED 31 DECEMBER 2024
Note Year ended Year ended
31 December 31 December 2023
2024 £000
£000
Revenue 2 43,651 49,466
Cost of sales:
Depletion, depreciation and amortisation (6,472) (8,241)
Other costs of sales (22,318) (24,135)
(28,790) (32,376)
Gross profit 14,861 17,090
Administrative expenses (7,422) (7,290)
Research and non-capitalised development costs (1,973) (2,002)
Exploration and evaluation assets impaired 6 (1,854) (456)
Impairment of development costs 6 (4,259) -
Impairment of goodwill 6 - (130)
Gain/(loss) on derivative financial instruments 737 (25)
Other expense (2,000) -
Other income 3 8
Operating (loss)/profit (1,907) 7,195
Finance costs 3 (4,805) (4,426)
Change in fair value of contingent consideration 10 2,251 -
(Loss)/profit before tax (4,461) 2,769
Income tax 4 (8,133) (8,260)
Loss after tax (12,594) (5,491)
Attributable to:
Owners of the Parent Company (11,295) (4,493)
Non-controlling interest (1,299) (998)
(12,594) (5,491)
Loss per share attributable to equity shareholders:
Basic loss per share 5 (8.74p) (3.52p)
Diluted loss per share 5 (8.74p) (3.52p)
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE YEAR ENDED 31 DECEMBER 2024
Year ended Year ended
31 December 31 December
2024 2023
£000 £000
Loss for the year (12,594) (5,491)
Other comprehensive income for the year:
Items that may be reclassified subsequently to profit or loss:
Foreign exchange differences on translation of foreign operations 117 19
Total comprehensive loss for the year (12,477) (5,472)
Total comprehensive loss attributable to:
Owners of the Parent Company (11,181) (4,477)
Non-controlling interest (1,296) (995)
(12,477) (5,472)
CONSOLIDATED BALANCE SHEET
AS AT 31 DECEMBER 2024
Note 31 December 31 December
2024 2023
£000 £000
ASSETS
Non-current assets
Intangible assets 6 7,736 13,823
Property, plant and equipment 7 70,657 73,994
Right-of-use assets 7,253 7,426
Restricted cash 8 4,282 -
Deferred tax asset 4 31,054 37,192
120,982 132,435
Current assets
Inventories 1,497 1,522
Trade and other receivables 6,381 7,067
Cash and cash equivalents 8 4,708 3,855
Restricted cash 8 - 410
Derivative financial instruments 398 -
12,984 12,854
Total assets 133,966 145,289
LIABILITIES
Current liabilities
Trade and other payables (6,731) (10,971)
Corporation tax payable 4 (3,073) (1,099)
Borrowings 9 (6,488) (5,358)
Lease liabilities (1,145) (865)
Provisions 10 (1,335) (2,236)
(18,772) (20,529)
Non-current liabilities
Borrowings 9 (5,246) -
Other payables (440) -
Lease liabilities (6,830) (6,981)
Provisions 10 (60,035) (62,906)
(72,551) (69,887)
Total liabilities (91,323) (90,416)
Net assets 42,643 54,873
EQUITY
Capital and reserves
Called up share capital 30,334 30,334
Share premium account 103,248 103,189
Foreign currency translation reserve 3,929 3,815
Other reserves 38,512 38,324
Accumulated deficit (132,331) (121,036)
Equity attributable to owners of the Company 43,692 54,626
Non-controlling interest (1,049) 247
Total equity 42,643 54,873
These financial statements were approved and authorised for issue by the Board
on 29 April 2025 and are signed on its behalf by:
Ross Glover
Frances Ward
Chief Executive Officer
Chief Financial Officer
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 31 DECEMBER 2024
Called up Share Foreign Other Accumulated deficit Equity attributable to owners of the Company £000 Non-controlling Interest Total
share capital premium currency reserves** £000 £000 equity
£000 account translation £000 £000
£000 reserve*
£000
At 1 January 2023 30,334 103,068 3,799 37,617 (116,543) 58,275 - 58,275
Loss for the year - - - - (4,493) (4,493) (998) (5,491)
Acquisition of subsidiary with non-controlling interest - - - - - - 1,242 1,242
Share options issued under the employee share plan - - - 707 - 707 - 707
Issue of shares - 121 - - - 121 - 121
Currency translation adjustments - - 16 - - 16 3 19
At 31 December 2023 30,334 103,189 3,815 38,324 (121,036) 54,626 247 54,873
Loss for the year - - - - (11,295) (11,295) (1,299) (12,594)
Share options issued under the employee share plan - - - 188 - 188 - 188
Issue of shares - 59 - - - 59 - 59
Currency translation adjustments - - 114 - - 114 3 117
At 31 December 2024 30,334 103,248 3,929 38,512 (132,331) 43,692 (1,049) 42,643
* The foreign currency translation reserve includes an amount of £3,799
thousand (2023: £3,799 thousand) relating to exchange gains and losses on
translation of net assets and results, and intercompany balances, which formed
part of the net investment of the Group, in respect of subsidiaries which
previously operated with a functional currency other than UK pound sterling.
** Other reserves include: 1) Share plan reserves comprising a EIP/MRP/EDRP
reserve representing the cost of share options issued under the long term
incentive plans and share incentive plan reserve representing the cost of the
partnership and matching shares; 2) a treasury shares reserve which represents
the cost of shares in Star Energy Group plc purchased in the market to satisfy
awards held under the Group incentive plans; 3) a capital contribution reserve
which arose following the acquisition of IGas Exploration UK Limited; and 4) a
merger reserve which arose on the reverse acquisition of Island Gas Limited.
(
)
CONSOLIDATED CASH FLOW STATEMENT
FOR THE YEAR ENDED 31 DECEMBER 2024
Note Year ended Year ended
31 December 2024 31 December 2023
£000 £000
Cash flows from operating activities:
(Loss)/profit before tax (4,461) 2,769
Depletion, depreciation and amortisation 6,517 8,291
Abandonment costs/other provisions utilised or released (1,672) (2,186)
Share-based payment charge 195 633
Exploration and evaluation assets impaired 6 1,854 456
Impairment of development costs 6 4,259 -
Impairment of goodwill 6 - 130
Change in fair value of contingent consideration 10 (2,251) -
Unrealised (gain)/loss on oil price derivatives (398) 525
Gain on sale of fixed assets (3) (8)
Finance costs 3 4,805 4,426
Operating cash flows before working capital movements 8,845 15,036
(Increase)/decrease in trade and other receivables and other financial assets (1,397) 1,482
)
(Decrease)/increase in trade and other payables (1,334) 553
(Increase) in restricted cash (3,872) -
Decrease in inventories 25 145
Net cash generated from operating activities 2,267 17,216
Cash flows from investing activities:
Purchase of intangible exploration and evaluation assets (67) (343)
Purchase of property, plant and equipment (5,579) (7,547)
Purchase of intangible development assets (30) (619)
Acquisition of subsidiary, net of cash acquired - (1,282)
Proceeds from disposal of property, plant and equipment 3 152
Net cash used in investing activities (5,673) (9,639)
Cash flows from financing activities:
Cash proceeds from issue of ordinary share capital 28 42
Drawdown on finance facility 8 12,530 -
Repayment of Reserves Based Lending facility 8 (5,541) (3,284)
Transaction costs related to loan refinancing 8 (610) -
Repayment of principal portion of lease liabilities (887) (1,255)
Repayment of interest on lease liabilities (709) (727)
Interest paid 8 (493) (1,360)
Net cash generated from/(used in) financing activities 4,318 (6,584)
Net increase in cash and cash equivalents in the year 912 993
Net foreign exchange differences 8 (59) (230)
Cash and cash equivalents at the beginning of the year 3,855 3,092
Cash and cash equivalents at the end of the year 8 4,708 3,855
CONSOLIDATED FINANCIAL STATEMENTS - NOTES
FOR THE YEAR ENDED 31 DECEMBER 2024
1 Material accounting policies
(a) Basis of preparation of financial statements
Whilst the financial information in this preliminary announcement has been
prepared in accordance with international accounting standards (IFRS) in
conformity with the requirements of the Companies Act 2006 ("the "Standards"),
this announcement does not contain sufficient information to comply with the
Standards. The Group will publish full financial statements that comply with
the Standards in May 2025.
The financial information for the year ended 31 December 2024 does not
constitute statutory financial statements as defined in sections 435 (1) and
(2) of the Companies Act 2006. Statutory financial statements for the year
ended 31 December 2023 have been delivered to the Registrar of Companies and
those for 2024 will be delivered following the Company's annual general
meeting. The auditor has reported on the 2024 financial statements and their
report was unqualified. The report did not contain a statement under section
498 (2) or (3) of the Companies Act 2006.
The accounting policies applied are consistent with those adopted and
disclosed in the Group's financial statements for the year ended 31 December
2023. There have been certain amendments to accounting standards issued by the
International Accounting Standards Board which were applicable from 1 January
2024. These did not have a material impact on the accounting policies,
methods of computation or presentation applied by the Group.
There are also new accounting standards and certain amendments to existing
accounting standards issued by the International Accounting Standards Board
which will be applicable from either 1 January 2025 or from periods subsequent
to that date. These have not been adopted early and are not expected to have
a material impact on the accounting policies, methods of computation or
presentation applied by the Group other than IFRS 18 Presentation and
Disclosure in Financial Statements which was issued on 9 April 2024, effective
for periods beginning on or after 1 January 2027. We are in the process of
assessing the impact of this standard on our future financial statements.
Further details on new International Financial Reporting Standards adopted and
yet to be adopted will be disclosed in the 2024 Annual Report and Financial
Statements.
Star Energy Group plc is a public limited company incorporated and registered
in England and Wales and is listed on the Alternative Investment Market
("AIM"). The Group's principal activities are exploring for, appraising,
developing and producing oil and gas and developing geothermal projects.
The financial information is presented in UK pounds sterling and all values
are rounded to the nearest thousand (£000) except when otherwise indicated.
Prior year numbers have been reclassified, where necessary, to conform to the
current year presentation.
(b) Going concern
The Group continues to closely monitor and manage its liquidity. Cash flow
forecasts for the Group are prepared on a monthly basis based on, inter alia,
the Group's production and expenditure forecasts, management's best estimate
of future oil prices and foreign exchange rates and the Group's available loan
facility. Sensitivities are run to reflect different scenarios including, but
not limited to, possible reductions in commodity prices, fluctuations in
exchange rates and reductions in forecast oil production rates.
The current geopolitical climate and the impact of an increase in trade
tariffs on the global economy has reduced crude oil prices in the first
quarter of 2025, with volatility in oil prices and foreign exchange rates
likely to continue whilst countries seek to negotiate trade agreements with
the US.
The focus of the Group in 2024 has been to strengthen our balance sheet and
improve our resilience to oil price volatility. We have generated strong
operating cashflows in 2024 as a result of stable production and a continued
effort to minimise operating costs. We have also carried out a reorganisation
resulting in a material reduction in general and administrative costs going
into 2025. The €25 million finance facility agreed with Kommunakkredit, and
the sale of non-core land with the proceeds of £6.3 million being received in
April 2025, further improves our liquidity position.
However, the ability of the Group to operate as a going concern is dependent
upon the continued availability of future cash flows and the availability of
the monies drawn under its loan facility, which is dependent on the Group not
breaching the facility's covenants. To mitigate these risks, the Group
benefits from its hedging policy with 146,200 barrels hedged for 2025 using
swaps at an average price of $75/bbl.
The Group's base case cash flow forecast was run with average oil prices of
$65/bbl for the remainder of 2025 and $70/bbl for 2026, foreign exchange rates
of an average $1.31/£1 for the remainder of 2025 and $1.28/£1 for 2026. In
this base case scenario, our forecasts show that the Group will have
sufficient liquidity as well as sufficient financial headroom to meet the
applicable financial covenants for the 12 months from the date of approval of
the financial statements.
Management has also prepared a "severe but plausible" downside case, which
reflects the possible impact of global economic uncertainties resulting in the
oil price dropping to $55/bbl in Q2 2025 before recovering to $58/bbl in Q3
and Q4 2025, and to an average of $62/bbl in 2026. In this downside case
management has assumed foreign exchange rates of an average $1.33/£1 for the
remainder of 2025 and $1.33/£1 for 2026. Our downside case also includes a
reduction in production of 5% throughout the going concern period. In the
event of a downside scenario, management has the ability to drawdown further
under the loan facility as well as to take mitigating actions including
delaying capital expenditure and reducing costs, in order to maintain
liquidity and to remain within the Group's financial covenants over the
remaining facility period, should such actions be necessary. All such
mitigating actions are within management's control. In this downside scenario
including mitigating actions, our forecast shows that the Group will have
sufficient financial liquidity as well as sufficient headroom to meet its
financial covenants for the 12 months from the date of approval of the
financial statements. Management remain focused on maintaining a strong
balance sheet and funding to support our strategy.
Based on the analysis above, the Directors have a reasonable expectation that
the Group has adequate resources to continue as a going concern for at least
the next twelve months from the date of the approval of the Group financial
statements and have concluded it is appropriate to adopt the going concern
basis of accounting in the preparation of the financial statements.
2 Revenue
The Group derives revenue solely within the United Kingdom from the transfer
of control over the goods and services to external customers, which is
recognised at a point in time when the performance obligation has been
satisfied by the transfer of goods. The Group's major product lines are:
Year ended Year ended
31 December 31 December
2024 2023
£000 £000
Oil sales 42,794 46,448
Electricity sales 550 1,162
Gas sales 249 1,856
Other 58 -
43,651 49,466
Revenues of approximately £21.6 million and £21.2 million were derived from
the Group's two largest customers (2023: £23.6 million and £22.8 million)
and are attributed to the oil sales.
As at 31 December 2024, there are no contract assets or contract liabilities
outstanding (2023: nil).
3 Finance costs Year Year
ended ended
31 December 31 December
2024 2023
£000 £000
Interest on borrowings (817) (885)
Amortisation of finance fees on borrowings (226) (268)
Net foreign exchange (loss)/gain (84) 153
Unwinding of discount on decommissioning provision (note 10) (2,537) (2,596)
Interest charge on lease liability (709) (727)
Other interest payable (432) (103)
(4,805) (4,426)
4 Income tax
(i) Tax charge on (loss)/profit from continuing ordinary activities Year ended Year ended
31 December 31 December
2024 2023
£000 £000
Current tax:
Charge for the year 2,110 1,099
Adjustments in respect of prior periods (136) -
Total current tax charge 1,974 1,099
Deferred tax:
Charge relating to the origination or reversal of temporary differences 6,570 8,611
Credit due to tax rate changes (1,070) -
Charge/(credit) in relation to prior years 659 (1,450)
Total deferred tax charge 6,159 7,161
Total income tax charge 8,133 8,260
ii) Factors affecting the tax charge
The majority of the Group's profits are generated by "ring-fence" businesses
which attract UK corporation tax and supplementary charges at a combined
average rate of 40% (2023: 40%), in addition to the Energy Profit Levy (EPL)
introduced in May 2022 with an average rate of 36% for the year (2023: 35%).
A reconciliation of the UK statutory corporation tax rate (applicable to oil
and gas companies) applied to the Group's (loss)/profit before tax to the
Group's total tax charge is as follows:
Year ended Year ended
31 December 31 December
2024 2023
£000 £000
(Loss)/profit before tax (4,461) 2,769
Expected tax charge/(credit) based on (loss)/profit multiplied by an average (3,368) 2,077
combined rate of corporation tax and supplementary charge and Energy Profit
Levy in the UK of 76% (2023: 75%)
Tax charge/(credit) in respect of prior years 523 (1,450)
Expenses not allowable for tax purposes 469 1,502
Differences in amounts not allowable for supplementary charge purposes* 99 (29)
Impact of profits or losses taxed or relieved at different rates 3,484 1,218
Net increase in unrecognised losses carried forward 7,808 5,178
Net increase/(decrease) in unrecognised temporary taxable differences 188 (236)
Tax rate change (1,070) -
Tax charge on (loss)/profit 8,133 8,260
* Amounts not allowable for supplementary charge purposes relate to net
financing costs disallowed for supplementary charge offset by investment
allowance, which is deductible against profits subject to supplementary
charge.
iii) Deferred tax
The movement on the deferred tax asset in the year is shown below:
2024
£000 2023
£000
Asset at 1 January 37,192 44,813
Tax (charge)/credit relating to prior year (659) 1,450
Tax charge during the year (6,570) (8,611)
Tax credit arising due to the changes in tax rates 1,070 -
Deferred tax arising from business combination - (454)
Exchange differences 21 (6)
Asset at 31 December 31,054 37,192
The following is an analysis of the deferred tax asset by category of
temporary difference:
31 December 31 December
2024 2023
£000 £000
Accelerated capital allowances (24,439) (25,321)
Tax losses carried forward 34,924 44,388
Investment allowance unutilised 2,311 2,051
Decommissioning provision 18,104 15,737
Unrealised gains or losses on derivative contracts (310) -
Share-based payments 42 68
Right-of-use asset and liability 422 269
Deferred tax asset 31,054 37,192
iv) Corporation tax payable
The movement on the Corporation tax payable in the year is shown below:
2024
£000 2023
£000
Payable at 1 January (1,099) -
Tax charge during the year (2,110) (1,099)
Adjustment in respect of prior periods 136 -
Payable at 31 December 3,073 (1,099)
v) Tax losses
The Group has gross total tax losses and similar attributes carried forward of
£367.8 million (2023: £362.1 million). Deferred tax assets have been
recognised in respect of tax losses and other temporary differences where the
Directors believe it is probable that these assets will be recovered based on
a five-year profit forecast or to the extent that there is offsetting deferred
tax liabilities. Such recognised tax losses include £85.0 million (2023:
£109.5 million) of ringfence corporation tax losses which will be recovered
at 30% of future taxable profits, £70.2 million (2023: £92.6 million) of
supplementary charge tax losses which will be recovered at 10% of future
taxable profits and £4.1 million (2023: £4.3 million) of losses arising
under the EPL regime which will be recovered at 38% of future taxable
profits.
vi) Changes in legislation
In October 2024, the UK Government announced the following changes to the EPL
regime:
· An increase in the EPL rate from 35 per cent to 38 per cent
· Removal of the main EPL investment allowance of 29%
· An extension of the EPL regime to 31 March 2030.
The rate increase and the investment allowance removal were substantively
enacted at the balance sheet date and took effect from 1 November 2024. These
changes resulted in an increase in the tax charge of £0.3 million. The EPL
extension to 31 March 2030 was substantively enacted on 3 March 2025 and is
therefore not reflected in the financial statements as at 31 December 2024.
This impact will be included in the financial statements for the following
period. Had the extension been enacted at the balance sheet date, an
additional deferred tax charge of £2.7 million would have been recognised in
the current financial statements.
5 Earnings per share (EPS)
Basic EPS amounts are based on the loss for the year after taxation
attributable to the ordinary equity holders of the Parent Company of £11.3
million (2023: £4.5 million) and the weighted average number of ordinary
shares outstanding during the year of 129.3 million (2023: 127.7 million).
Diluted EPS amounts are based on the loss for the year after taxation
attributable to the ordinary equity holders of the Parent Company and the
weighted average number of ordinary shares outstanding during the year plus
the weighted average number of ordinary shares that would be issued on the
conversion of all the potentially dilutive ordinary shares into ordinary
shares, except where these are anti-dilutive.
As at 31 December 2024, there are 6.0 million potentially dilutive share
options (31 December 2023: 7.5 million potentially dilutive share options)
which were not included in the calculation of diluted earnings per share as
their conversion to ordinary shares would have decreased the loss per share.
The following reflects the income and share data used in the basic and diluted
earnings per share:
Year ended Year ended
31 December 31 December
2024 2023
Basic loss per share - ordinary shares of 0.002 pence each (8.74p) (3.52p)
Diluted loss per share - ordinary shares of 0.002 pence each (8.74p) (3.52p)
Loss for the year attributable to equity holders of the Parent Company - £000 (11,295) (4,493)
Weighted average number of ordinary shares in the year- basic EPS 129,275,299 127,671,520
Weighted average number of ordinary shares in the year- diluted EPS 129,275,299 127,671,520
6 Intangible assets
2024 2023
Exploration and evaluation assets Goodwill Development costs Total Exploration and evaluation assets Goodwill Development costs Total
£'000 £'000 £'000 £'000 £'000 £'000 £'000 £'000
At 1 January
5,655 1,196 6,972 13,823 5,558 - 3,710 9,268
Additions
176 - 30 206 553 - 705 1,258
Amounts recognised on acquisition of a subsidiary
- - - - - 1,311 2,529 3,840
Exchange differences
- (55) (117) (172) - 15 28 43
Transfer to property, plant and equipment
(8) - - (8) - - - -
Impairment
(1,854) - (4,259) (6,113) (456) (130)* - (586)
At 31 December
3,969 1,141 2,626 7,736 5,655 1,196 6,972 13,823
Exploration and evaluation assets
Exploration costs impaired in the financial year to 31 December 2024 were
£1.9 million (2023: £0.5 million) which were substantially all related to
the capitalised exploration costs at PEDL 235, where the Board decided not to
renew our exploration licence given the potential challenges with obtaining
relevant planning and regulatory approvals.
The 2023 exploration costs impaired included £0.3 million of early-stage
projects relating to our conventional assets where it was assessed that there
was no further development prospect and £0.2 million related to trailing
costs on previously impaired unconventional licences.
The remaining £4.0 million (2023: £5.7 million) of capitalised exploration
expenditure relates to our conventional assets including PL 240. Management
has assessed the remaining capitalised exploration expenditure for indications
of impairment under IFRS 6 Exploration for and Evaluation of Mineral Resources
and did not identify any factors indicating a need to perform detailed
impairment testing.
Goodwill
The carrying value of goodwill relates to the acquisition of an interest in
A14 Energy Limited during 2023. The Group has identified four Cash Generating
Units (CGUs) within our geothermal business, whereby technical, economic
and/or contractual features create underlying interdependence in the cash
flows. These CGUs correspond to the three Croatian geothermal licences
(Ernestinovo, Sječe and Pčelić) and the UK geothermal business. The
carrying amount of goodwill has been allocated to the following CGUs:
31 December 2024 31 December 2023
£000 £000
Sječe licence 352 369
Pčelić licence 351 368
Ernestinovo licence 438 459
1,141 1,196
* During the previous year, goodwill of £0.1 million allocated to the
Leščan CGU was fully impaired since the related licence was not awarded to
the Group. No goodwill has been allocated to the UK geothermal business CGU.
The Group reviewed the carrying value of the Sječe licence and Pčelić
licence CGUs at 31 December 2024 and assessed them for impairment. The
recoverable amount for these CGUs was based on their fair value less costs of
disposal which was calculated using key assumptions in relation to electricity
generation volumes, future electricity prices, project capital expenditure and
discount rate. The recoverable amount was higher than the carrying values of
these CGUs, hence no impairment charge was recognised against allocated
goodwill during the year.
The Group also reviewed the carrying value of the Ernestinovo licence CGU
(which includes the related goodwill) at 31 December 2024, as further detailed
below, with no impairment charge being recognised against goodwill allocated
to this CGU in the year (2023: £nil).
Development costs
Development costs relate to assets acquired as part of the GT Energy
acquisition in 2020, and assets acquired relating to the Ernestinovo licence
as part of the A14 Energy acquisition in 2023.
The carrying amount of development costs is split between CGUs as follows:
31 December 2024 31 December 2023
£000 £000
UK Geothermal business 186 4,415
Ernestinovo licence 2,440 2,557
2,626 6,972
Development costs relating to UK Geothermal business
The costs allocated to this CGU primarily related to the design and
development of deep geothermal heat projects in the United Kingdom, with the
principal project being at Etruria Valley, Stoke-on-Trent.
At 30 June 2024 the Group reviewed the carrying value of the development costs
and assessed it for impairment. Following the launching of the Green Heat
Network Fund (GHNF) by the UK government in March 2022, it had been the
intention that 50% of the project's total combined commercialisation and
construction costs would be funded through a grant from the fund. A grant
funding request was jointly submitted by GT Energy and SSE in the second half
of 2022, with SSE as lead applicant. Following an extended due diligence
process (with technical and commercial aspects of the project being signed off
by a third-party consultant in 2023), in 2024, SSE submitted a project change
request seeking to amend the capital grant and timetable. Further amendments
saw the project change its focus to being fed by a proposed new 'Energy from
Waste' facility. This meant that the project could not progress in its
intended form. Therefore, the decision was taken at 30 June 2024 to fully
impair the capitalised amounts relating to the Stoke project, resulting in an
impairment charge of £4.3 million (2023: £nil).
Development costs relating to Ernestinovo licence
The development costs associated with Ernestinovo licence relate to the fair
value of assets acquired as part of the A14 Energy acquisition made in 2023.
The costs relate to the value of the licence award and work performed up to
the acquisition date in progressing with the re-entry of an existing well on
the licence.
The Group reviewed the carrying value of the Ernestinovo licence CGU as at 31
December 2024 and assessed it for impairment. The recoverable amount for the
CGU was based on its fair value less costs of disposal which was calculated
using key assumptions in relation to electricity generation volumes, future
electricity prices, project capital expenditure and discount rate. The
recoverable amount calculated above was higher than the carrying value of the
CGU, hence no impairment charge was recognised against capitalised development
cost or allocated goodwill during the year (2023: £nil).
7 Property, plant and equipment
2024 2023
Oil and gas Other property, plant and equipment Total Oil and gas Other property, plant and equipment Total
assets £'000 £'000 assets £'000 £'000
£'000 £'000
Cost
At 1 January 226,888 1,734 228,622 220,301 2,046 222,347
Additions 4,812 - 4,812 6,920 27 6,947
Transfer from exploration and evaluation assets 8 - 8 - - -
Disposals/write-offs - (25) (25) - (339) (339)
Changes in decommissioning* (2,829) - (2,829) (333) - (333)
At 31 December 228,879 1,709 230,588 226,888 1,734 228,622
Accumulated Depreciation, Depletion and Impairment
At 1 January 154,004 624 154,628 147,022 594 147,616
Charge for the year 5,293 35 5,328 6,982 30 7,012
Disposals/write-offs - (25) (25) - - -
At 31 December 159,297 634 159,931 154,004 624 154,628
NBV at 31 December 69,582 1,075 70,657 72,884 1,110 73,994
*The decommissioning asset reduced in line with the decommissioning liability
following a review of the estimate at 31 December 2024 (note 10).
Capital expenditure incurred during the year mostly related to upgrades at
various sites and a number of projects carried out to generate near-time
production and to offset field declines by upgrading existing facilities and
systems and optimising production at a number of sites.
Impairment of oil and gas assets
Year ended 31 December 2024
Cash Generating Units (CGUs) for impairment purposes are the group of fields
whereby technical, economic and/or contractual features create underlying
interdependence in the cash flows. The Group has identified the three main
producing CGUs as: North, South, and Scotland. At each balance sheet date, the
Group assesses its CGUs for impairment whenever events or changes in
circumstances indicate that the carrying amount of the CGU may not be
recoverable. If any such indication exists, the Group makes an estimate of the
asset's recoverable amount. An impairment assessment was performed for all
three CGUs at the balance sheet date as a result of the identification of
impairment indicators, mainly a downward revision in the reserve estimates and
changes to the Energy Profits Levy regime in the year. An impairment indicator
was noted for the Scotland CGU given the delay in the finalisation of the
potential sale of the underlying site.
The recoverable amounts of the North and South CGUs have been estimated by
assessing the fair value less costs of disposal using a discounted cash flow
methodology. The recoverable amount of the Scotland CGU has been estimated by
assessing the fair value less costs of disposal with respect to a potential
sale of the site.
The future cash flows in the discounted cash flow models for the North and
South CGUs were estimated using the following key assumptions:
· Group's estimate of proved plus probable reserves at the balance
sheet date
· Oil price (Brent): $75-$70/bbl for the years 2025-2029 and
$75/bbl thereafter
· USD/GBP foreign exchange rate: Range of $1.25:£1.00 -
$1.30:£1.00
· Post-tax discount rate: 9.9%
Outcome of impairment reviews:
The 31 December 2024 impairment assessment resulted in a recoverable amount
greater than the carrying amount by £5.8 million in the South CGU
(recoverable amount of £35.1 million) and £1.9 million in the North CGU
(recoverable amount of £33.1 million). At the Scotland CGU, no impairment
charge was recognised, with the recoverable amount of £0.5 million assessed
to approximate the carrying value of the CGU (which includes the carrying
value of the associated decommissioning liability).
Sensitivity of changes in assumption:
The principal assumptions in the discounted cashflow methodology are future
production, estimated Brent prices, the USD/GBP long-term foreign exchange
rate, and the discount rate. The impact on the recoverable amount that would
result from changes to the key assumptions at 31 December 2024 are shown
below:
CGU 10% reduction in price 10% reduction in production Increase in USD/GBP long-term foreign exchange rate to $1.35 Increase in discount rate by 1%
£m £m £m £m
North (8.82) (8.87) (2.46) (1.72)
South (8.32) (9.94) (2.75) (1.91)
The sensitivity analysis above does not take into account any mitigating
actions available to management should these changes occur, such as
implementing cost savings and other process efficiencies.
No impairment charge has been recognised for the North, South or Scotland
CGUs.
Year ended 31 December 2023
At 31 December 2023, an impairment assessment was performed for the North,
South and Scotland CGUs as a result of identification of impairment
indicators. The recoverable amounts of the North and South CGUs were estimated
by assessing the fair value less costs of disposal using a discounted cash
flow methodology. The recoverable amount of the Scotland CGU was estimated by
assessing the fair value less costs of disposal with respect to a potential
sale of the site.
The future cash flows in the discounted cash flow models for the North and
South CGUs were estimated using the following key assumptions:
· Group's estimate of proved plus probable reserves at the balance
sheet date
· Oil price (Brent): $78-$70/bbl for the years 2024-2028 and
$65/bbl thereafter
· USD/GBP foreign exchange rate: Range of $1.27:£1.00 -
$1.30:£1.00
· Post-tax discount rate: 9.5%
Outcome of impairment reviews:
The 31 December 2023 impairment assessment resulted in a recoverable amount
greater than the carrying amount by £16.9 million in the South CGU
(recoverable amount of £45.5 million) and £6.3 million in the North CGU
(recoverable amount of £38.2 million). Despite historic impairments remaining
un-reversed in the North CGU, no impairment reversal was recorded at the North
CGU as reasonable downside cases indicated that an impairment could be
required if certain plausible sensitivities were applied. Therefore, the
factors that led to the initial impairment were assessed to have not fully
reversed and management did not consider it appropriate to reverse a portion
of the past impairment. At the Scotland CGU, no impairment charge was
recognised, with the recoverable amount of £0.5 million assessed to
approximate the carrying value of the CGU (which included the carrying value
of the associated decommissioning liability).
8 Cash and cash equivalents
31 December 31 December
2024 2023
£000 £000
Cash at bank and in hand 4,708 3,855
Cash and cash equivalents do not include restricted cash.
Restricted cash
31 December 31 December
2024 2023
£000 £000
Current - 410
Non-current 4,282 -
Restricted cash represents amounts held in a deposit account with a commercial
bank as a collateral in support of performance guarantees issued by Tokio
Marine Europe S.A. (an insurance company) for licence commitments relating to
the Sječe and Pčelić, exploration licences. The deposit is subject to
restrictions during the tenure of the related performance guarantees and hence
not available for general use of the Group.
The previous year amount related to restoration deposits paid to
Nottinghamshire County Council, which served as collateral for the restoration
of drilling sites at the end of their life. This amount was collected in full
during the year.
Net debt reconciliation
31 December 31 December
2024 2023
£000 £000
Cash and cash equivalents 4,708 3,855
Borrowings - including capitalised fees (11,734) (5,358)
Net debt (7,026) (1,503)
Capitalised fees (503) (133)
Net debt excluding capitalised fees (7,529) (1,636)
2024 2023
Cash and cash equivalents Borrowings Total Cash and cash equivalents Borrowings Total
£000 £000 £000 £000 £000 £000
Net debt as at 1 January 3,855 (5,358) (1,503) 3,092 (8,743) (5,651)
Interest paid on borrowings (479) - (479) (809) - (809)
Other Interest paid (14) - (14) (575) - (575)
12
Drawdown on finance facility (note 9) 12,530 (12,530) - - - -
Repayment of RBL (note 9) (5,541) 5,541 - (3,284) 3,284 -
Foreign exchange adjustments (59) 229 170 (230) 369 139
Capitalised transaction costs (610) 610 - - - -
Cash backing of performance guarantees (4,282) - (4,282) - - -
Other cash flows (692) - (692) 5,661 - 5,661
Other non-cash movements - (226) (226) - (268) (268)
Net debt as at 31 December 4,708 (11,734) (7,026) 3,855 (5,358) (1,503)
9 Borrowings
31 December 31 December
2024 2023
£000 £000
Reserve-Based Lending Facility (RBL) - secured (current) - (5,358)
Finance facility - secured (current) (6,488) -
Finance facility - secured (non-current) (5,246) -
(11,734) (5,358)
The carrying amounts of each of the Group's financial liabilities included
within borrowings are considered to be a reasonable approximation of their
fair value.
During the year, on 9 April 2024, the Group secured a €25.0 million finance
facility with Kommunalkredit Austria AG (Kommunalkredit). The facility
comprises of a facility A which was used to fund the repayment of the
outstanding balance on the reserves based loan (RBL) facility and carries a
fixed interest rate of 9.4% and is repayable on 30 June 2025 and a facility B
which primarily provides funding for the Group's geothermal development
activities and carries an interest rate of Euribor + 6% and has a five-year
term with repayments commencing on 31 December 2025.
The Group is subject to the following financial covenants under the facility
agreement, to be calculated and tested for compliance at 30 June and 31
December for each year of the agreement, in addition to when drawdowns are
made, or as otherwise required by the facility agreement:
· Loan Life Cover Ratio ("LLCR") of greater than or equal to
1.25:1.
· Net Debt to Earnings before Interest, Tax, Depreciation,
Amortisation, and Exceptional items ("EBITDAX") ratio of less than or equal to
2.00:1.
· Current ratio of the Group as defined in the facility agreement
of greater than or equal to 1.00:1.
· Debt Service Cover Ratio ("DSCR") of greater than or equal to
1.10:1, for both projected and historic figures.
· Proved and developed reserves value to Net Debt ratio of greater
than or equal to 2.50:1.
We complied with all the covenants applicable at the balance sheet date.
The balance at the end of the previous year related to the outstanding amount
under the $40.0 million RBL facility with BMO Capital Markets (BMO). The
facility was due to mature in June 2024 and the outstanding balance was repaid
in April 2024 from the proceeds of the Kommunalkredit facility. The facility
carried an interest rate of USD LIBOR plus 4.0% and was secured on the Group's
assets. USD LIBOR ceased to be published from 30 June 2023 and the facility
was amended to replace LIBOR with the Secured Overnight Finance Rate (SOFR)
with effect from 1 July 2023. There was no material impact on the financial
position and performance of the Group resulting from this transition.
Collateral against borrowing
A security agreement was executed between Apex Corporate Trustees (UK) Limited
(as security agent for Kommunalkredit Austria AG) ("Apex"), Star Energy Group
plc and certain subsidiaries, namely; IGas Energy Limited, Star Energy
Limited, IGas Energy Enterprise Limited, Island Gas (Singleton) Limited,
Island Gas Limited, Dart Energy (East England) Limited, Dart Energy (West
England) Limited, IGas Energy Development Limited, IGas Energy Production
Limited, Dart Energy (Europe) Limited and GT Energy UK Limited (as chargors)
dated 9 April 2024 ("Star Energy Debenture"). On the same date, Scottish bonds
and floating charges were executed between Apex (as security agent) and Dart
Energy (Europe) Limited and IGas Energy Production Limited (Star Energy Group
companies, as "Scottish Chargors") ("Scottish BFCs"). A further security
agreement was executed between GT Energy Croatia Limited (a Star Energy Group
company, as chargor) and Apex (as security agent) dated 26 April 2024 ("GT
Debenture").
Under the terms of the Star Energy Debenture and GT Debenture, Apex has fixed
charges over certain real property (freehold and/or leasehold property),
petroleum licences, all pipelines, plant, machinery, vehicles, fixtures,
fittings, computers, office and other equipment and chattels and all related
property rights, shares of certain subsidiaries as well as the assigned
agreements and rights and all related property rights and first floating
charges over property, assets, rights and revenues (other than those charged
or assigned pursuant to the aforementioned fixed charges). Under the terms of
the Scottish BFCs, Apex has a first floating charge over all of the assets of
the Scottish Chargors.
10 Provisions
2024 2023
Decommissioning provisions Contingent consideration Total Decommissioning provisions Contingent consideration Total
£'000 £'000 £'000 £'000 £'000 £'000
At 1 January (62,411) (2,731) (65,142) (62,825) (2,731) (65,556)
Acquisitions - - - - (857) (857)
Utilisation of provision 1,147 - 1,147 2,909 857 3,766
Unwinding of discount (note 3) (2,537) - (2,537) (2,596) - (2,596)
Foreign exchange adjustments 10 - 10 - - -
Changes in FV of contingent consideration - 2,251 2,251 - - -
Reassessment of decommissioning provision 2,901 - 2,901 101 - 101
At 31 December (60,890) (480) (61,370) (62,411) (2,731) (65,142)
2024 2023
Decommissioning provisions Contingent consideration Total Decommissioning provisions Contingent consideration Total
£'000 £'000 £'000 £'000 £'000 £'000
Current (855) (480) (1,335) (1,956) (280) (2,236)
Non-current (60,035) - (60,035) (60,455) (2,451) (62,906)
At 31 December (60,890) (480) (61,370) (62,411) (2,731) (65,142)
Decommissioning provision
The Group spent £1.1 million on decommissioning activities during the year
(2023: £2.9 million) related primarily to the Group's share of costs related
to plugging and abandoning wells at the Doe Green, Irlam and Springs Road
sites.
Provision has been made for the discounted future cost of abandoning wells and
restoring sites to a condition acceptable to the relevant authorities. This is
expected to take place between 1 to 31 years from year end (2023: 1 to 29
years). The provisions are based on the Group's internal estimate as at 31
December 2024. Assumptions are based on our cumulative experience from
decommissioning wells which management believes is a reasonable basis upon
which to estimate the future liability. The estimates are based on a planned
programme of abandonments but also include a provision to be spent in
2025-2029 on preparing for the abandonment campaign, abandoning wells and
restoring sites which for regulatory, integrity or other reasons fall outside
the planned campaign. The estimates are reviewed regularly to take account of
any material changes to the assumptions. Actual decommissioning costs will
ultimately depend upon future costs for decommissioning which will reflect
market conditions and regulations at that time. Furthermore, the timing of
decommissioning is uncertain and is likely to depend on when the fields cease
to produce at economically viable rates. This, in turn, will depend on factors
such as future oil prices, which are inherently uncertain.
The Group applies an inflation adjustment to the current cost estimates and
discounts the resulting cash flows using a risk free discount rate. The
provision estimate reflects a higher inflation percentage of 2.5% in the near
term for the period 2025 - 2026 and thereafter incorporates the long term UK
target inflation rate of 2% for the period 2027 and beyond. The discount rate
used in the provision calculation as at 31 December 2024 ranged from 3.0% to
6.3% (2023: 3.0% to 5.5%). The increase in the risk free discount rate during
the year is mainly due to the increase in the yield on UK government bonds for
periods comparable to the life of the provision.
At 31 December 2024, the Group reassessed the decommissioning provision which
resulted in a reduction of £2.9 million to the value of the liability. The
change comprises a £2.5 million decrease due to the change in the discount
rate and £0.7 million due to changes in expected costs offset by an increase
of £0.3 million due to changes in expected timing of abandonment activities.
Management performed sensitivity analysis to assess the impact of changes to
the risk free rate on the Group's decommissioning provision balance. A 0.5%
decrease in the risk free rate assumption would result in an increase in the
decommissioning provision by £4.5 million. Management also performed
sensitivity analysis to assess the impact of changes to the undiscounted
future cost of abandoning wells and restoring sites on the Group's
decommissioning provision balance. A 10% increase in the undiscounted future
cost would result in an increase in the decommissioning provision by £6.0
million.
Contingent consideration
The carrying value of contingent consideration relates to the acquisition of
GT Energy UK Limited (GT Energy). The consideration is payable in shares and
is dependent on the timing of various milestones being achieved. It is also
dependent on the inputs to an agreed-form economic model which determines the
level of the consideration for each milestone in accordance with the sale and
purchase agreement (SPA). These inputs relate to targets for aspects of the
Stoke-on-Trent project, including funding, amount of heat delivered, and costs
and revenues achieved.
As detailed in note 6, it is now expected that the project will not progress
in its intended form. This means that it will not be possible to meet the
milestones, with the exception of a "business development" milestone (relating
to the development of a second project) which could result in a payment of up
to £1 million. Therefore the fair value for each milestone other than the
business development milestone has been assessed as £nil. The fair value of
the business development milestone was calculated by determining the
probability weighted value of the payment. The balance of the contingent
consideration at 31 December 2024 has been classified as a current liability
based on the contractual milestone payment dates in the SPA for the GT Energy
acquisition and the estimated timing of the achievement of the milestone.
In 2023, a contingent consideration of £0.9 million was recognised as part of
the acquisition of an interest in A14 Energy Limited which was payable on the
award of geothermal licences in bids submitted by IGeoPen d.o.o za trogovinu i
usluge. The outcome of the bids was announced in October 2023 with the
successful award of two licences, resulting in the contingent consideration
becoming payable. This amount was fully settled during 2024.
11 Subsequent events
· On 3 January 2025, the Group acquired a further 20% interest in
the issued share capital of its subsidiary A14 Energy Limited ("A14 Energy")
from the minority shareholder Peninsula International PTE Limited. As a
result, the Group's shareholding in A14 Energy increased from 51% to 71%. The
acquisition of the additional shareholding was completed by conversion of the
loan notes held by the Group.
· In April 2025, the Group completed the sale of its non-core
asset, the Holybourne site in Alton, Hampshire, for a consideration of £6.3
million. The site, previously the location of Star's decommissioned Holybourne
Oil Terminal, has now been transferred to the new owners following the
satisfaction of all sale conditions.
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