REG - Star Energy Group - Half-year Report
16/09/2025 07:00
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RNS Number : 4175Z Star Energy Group PLC 16 September 2025
16 September 2025
Star Energy Group plc (AIM: STAR)
("Star Energy" or "the Company" or "the Group")
Unaudited Interim results for the six months ended 30 June 2025
Star Energy announces its unaudited interim results for the six months to 30
June 2025.
Commenting today Ross Glover, Chief Executive Officer, said:
"We welcome the UK government's recent recognition of domestic energy's
strategic value, as reflected in policy priorities aimed at reducing reliance
on imported fossil fuels, enhancing energy security, and creating new green
jobs and economic growth. The mission of Great British Energy similarly
champions clean, secure, home-grown energy as a catalyst for job creation and
energy independence. Our strategy is closely aligned with these objectives: we
manage our oil and gas assets responsibly and efficiently, while reinvesting
operating cashflows into making our oil and gas business more resilient and
maturing our geothermal opportunities.
However, the operating environment remains challenging. Our core oil and gas
operations-critical to funding the Group-are under increasing strain from the
Energy Profits Levy, which has elevated the headline upstream tax rate to 78%.
This, combined with a more complex and costly regulatory environment, creates
substantial barriers just as the UK's dependence on energy imports remains
pronounced. In the first quarter of 2025, the country's net energy imports
underscored the urgent need to prioritise and support domestic supply.
Despite these headwinds, we remain committed to developing a robust UK
geothermal business and are lobbying the Government to provide consistent and
practical policy and regulatory support. With this support, the potential is
considerable: geothermal energy offers secure, low-carbon, and price-stable
heat at scale. We aim to be a highly active player in the energy transition
and are well-positioned to be so.
Promoting genuinely home-grown energy is essential-not only for strengthening
the UK's energy security, but also for supporting skilled employment,
generating tax receipts for the government, and fostering regional and
national growth. This opportunity is of strategic importance both to the
country and to Star Energy, and we are dedicated to realising its potential.
Our approach is disciplined and measured. We are focused on operational
excellence in our oil and gas business, making selective investments where
returns are compelling, and steadily advancing our geothermal development
pipeline in the UK and Croatia and generating value for shareholders"
Results Summary
Six months to 30 June 2025 Six months to
£m 30 June 2024
£m
Revenues 18.3 23.2
Adjusted EBITDA - oil and gas* 5.5 8.9
Adjusted EBITDA - geothermal* (1.0) (2.4)
Operating cashflow before working capital movements 4.8 4.4
Year ended
31 December 2024
£m
Net debt* (excluding capitalised fees) 2.7 7.5
Cash and cash equivalents 4.3 4.7
*these are alternative performance measures which are further detailed in the
financial review
Corporate & Financial Summary
· Cash balances as at 30 June 2025 were £4.3 million (31 December
2024: £4.7 million) and net debt reduced to £2.7 million (31 December 2024:
£7.5 million). £8.7 million (€10.2 million) remains undrawn under our
Finance facility which can be used to fund a portion of the Singleton
Gas-to-wire project and our geothermal activities.
· Adjusted EBITDA was £4.5 million. Lower commodity prices, a weaker
US dollar, and lower production impacted oil revenues. However, the savings of
£1.6 million that we have generated in administrative costs and reduced
expenditure on our Croatian geothermal licences has partially offset this.
· Operating cash flow before working capital movements increased to
£4.8 million (H1 2024: £4.4 million). Reduced cashflows from oil sales net
of hedges were more than offset by a reduction in administrative expenses,
geothermal expenditure and other expenses.
· We received £6.3 million of proceeds from the sale of our Holybourne
site.
· We invested £2.0 million in our oil and gas assets in the period
including on our Singleton gas-to-wire project and on smaller projects across
our sites to enhance production and optimise operations. Net cash capex for
FY 2025 is expected to be £8.4 million, primarily relating to our
conventional assets.
· We recognised a gain of £1.3 million on our commodity and foreign
exchange hedges, of which £0.5 million was realised in the period. We have
hedged 152,800 bbls with swaps for H2 2025 and Q1 2026 at an average price of
$72.9/bbl and have additionally created some downside protection for 237,800
bbls with a three-way put/call options for H2 2025 and for 2026(1). We have
also put in place USD/GBP foreign exchange hedges for $0.5 million/month at a
rate of $1.227/£1 for the remainder of 2025.
· The Group had ring fence tax losses of £249 million at 30 June 2025.
1 A summary of our commodity hedges is shown on our June 2025 AGM
trading update on our website
Operational Summary
· Net production averaged 1,894 boe/d in H1 2025 (H1 2024: 2,012
boe/d). Full year production is expected to be c.2,000 boe/d, in line with our
previous guidance.
· Work on our Singleton gas-to-wire project has started, and we have
entered into contracts for the procurement of two generators and the
connection to the grid. Planning permission was received for the cable
installation in July. We have been informed by the distribution network
operator that energisation of the grid connection will not be completed in
2025. Accordingly, whilst we are working with the operator to expedite this,
we expect the project's scheduled launch to be delayed into 2026.
· We are continuing the development of our UK geothermal pipeline and
are working with both public and private entities to expand this. During the
first half, we announced the following:
o MoU signed with the University of Southampton and Bring Energy to
decarbonise the existing Southampton District Heat Network and explore the
provision of geothermal heat to the University; and
o MoU signed with Veolia on the decarbonisation of heat supply to new and
existing customers. We will work together on decarbonising district heating
schemes, commercial buildings, hospitals, campuses and industrial processes.
· We have completed the detailed feasibility studies for our projects
at the Wythenshawe Hospital and Salisbury District Hospital, both of which
confirm the presence of viable geothermal reservoirs.
· We continue to mature our Croatia geothermal portfolio by
establishing the exploitation field within the Ernestinovo licence and
preparing the conceptual field development plan to be submitted to the
Croatian Ministry of Economy. Following the acquisition of magnetotelluric
data on both Sječe and Pčelić exploration licences, we are undertaking a
technical de-risking of the licences to enable a phased development of the
portfolio.
A results presentation will be available at
https://www.starenergygroupplc.com/investors/reports-publications-presentations
(https://www.starenergygroupplc.com/investors/reports-publications-presentations)
For further information please contact:
Star Energy Group plc
Tel: +44 (0)20 7993 9899
Ross Glover, Chief Executive Officer
Frances Ward, Chief Financial Officer
Zeus (Nominated Adviser and Broker)
Tel: +44 (0)20 3829 5000
Antonio Bossi (Investment Banking)
Simon Johnson (Corporate Broking)
Vigo Consulting
Tel: +44 (0)20 7390 0230
Patrick d'Ancona/Finlay Thomson/Peter Jacob
Introduction
Our value creation strategy remains clear and focused:
· Maximise cash returns from UK oil and gas operations to fund growth and
improve financial resilience
· Grow a high-quality geothermal platform with scalable, de-risked
opportunities in the UK and Croatia
· Maintain capital discipline and agility, with focus on value creation
Our core oil and gas business continues to be the source of all revenue for
the group. We have made good progress on optimising our existing producing
assets with a focus on profitability. The revenue generated from this business
enables us to further enhance and optimise operations whilst building a growth
story in geothermal in the UK and in Croatia. It should be noted that despite
the UK demand for oil and gas remaining strong and the government's own
projections demonstrating strong demand to 2050 and beyond, the operating
environment in the UK is hostile. The regulatory burden grows with increased
costs, often resulting in little to no real world environmental improvements
and increased delays, in particular with the Environment Agency, where the
processing time for environmental permits regularly exceeds a year. Planning
for growth is made more difficult due to the fiscal burden on the industry
with an effective 78% tax rate, even at depressed oil prices, meaning that
investment in both the oil and gas business as well as our geothermal
businesses is curtailed. The Energy Profits Levy (EPL), in particular, is a
significant handbrake on us developing our geothermal projects, the type of
project that the government should be promoting. We have been able to partly
offset inflationary impacts on operating costs and higher workover costs by
savings elsewhere, whilst maintaining our strong Health and Safety (HSE)
record. We have also achieved substantial reductions in our administrative
costs.
We are working hard on executing on our long-term growth strategy to develop a
geothermal energy business of scale. However, we are ensuring that expenditure
on this division is limited to activities where we can see a clear line of
sight to value creation. The future development of this sector is reliant on
businesses such as ours, with decades of highly relevant development and
operational skills derived from our oil and gas business. As such, much of the
work to progress our geothermal business is carried out by our existing team,
leveraging their oil and gas skillset.
The UK geothermal sector is underdeveloped, but the demand drivers, being heat
decarbonisation, energy security, and long-term predictable pricing, are all
intensifying. Our pipeline of private and public sector projects is growing,
and we are working with credible partners such as the NHS, Veolia, and Bring
Energy to mature that pipeline. Despite the growing demand for a utility scale
distributed decarbonised heat solutions, something that only geothermal can
satisfy, the government's focus on energy remains around electrification and
on wind and solar in particular. Whilst many within government recognise the
benefits, there remains no organised framework within which geothermal
projects are promoted and developed.
If the UK wants secure, price-stable, low-carbon heat at scale, we need to
treat geothermal like core infrastructure. A recently released report(1),
commissioned by the Department for Energy Security and Net Zero, identifies
life cycle cost savings of as much as 75% or more, between the First of a Kind
projects (FOAK) and the later-stage "N'th of a Kind" projects (NOAK).
To get there, we need to 'prime the pump' in the same way that solar and
offshore wind received vociferous government backing in the early days. Our
ask of government is simple:
· Consult on and implement a National Geothermal Strategy, including
targets for geothermal development and use, aligned with National System
Energy Operator (NESO) and heat network zoning policy;
· Create and implement compelling non-financial and financial
investment incentives for geothermal, including by making geothermal a focus
for investment by GB Energy and the National Wealth Fund; and
1. Department for Energy Security and Net Zero 2025: UK Geothermal Review and
Cost Estimations
· Dedicate additional cross-departmental policy-making resource and
attention to geothermal - including by establishing formal structures within
Government, involving industry experts, to develop policy recommendations.
In Croatia, we benefit from a supportive regulatory and investment climate for
geothermal as well as a suitable geology for the generation of electricity.
Whilst the regulatory system operates very efficiently, Croatian Government
delays to European Union approval of a new premium tariff for geothermal is
holding back investment across the sector. Despite this, we are finalising
technical de-risking of our licences to enable phased development. The
Croatian market provides access to scalable energy opportunities within a
jurisdiction that actively supports and encourages clean energy investment.
We are uniquely positioned to deliver value from cash-generative UK oil and
gas operations, while building a diversified energy business that can thrive
in multiple market scenarios. Our geothermal activities are not a pivot away
from hydrocarbons; rather they are a logical, deployment of our core strengths
in subsurface, permitting, and infrastructure development into a growth area.
Production Operations
Net production for the period averaged 1,894 boe/d (H1 2024: 2,012 boe/d).
Whilst well uptime was generally good across the portfolio, production
deferrals were due to unplanned outages on larger producing wells and grid
upgrades in the East Midlands, undertaken by the District Network Operator,
taking longer than scheduled. Due to the combination of low oil prices,
increased regulatory costs and the penal tax rate, certain wells that we would
have otherwise brought back into production have remained temporarily shut-in
as it did not make economic sense to bring them back online. In spite of
planned summer shutdowns, production has recovered in July and August with
August production at 1,976 boe/d.
The rolling programme of well optimisation and stimulation continues. We are
offsetting the natural declines in our fields by investing in quick returning
projects generally deploying small amounts of capital to optimise specific
wells.
Development Projects
Work has begun on our Singleton gas-to-wire project which will deliver c.75
boe/d utilising gas which is currently being flared and meet the HSE
requirements for the continued operation of the site. The project now has
planning consent and a secured grid connection. Work on the project has
started and we have entered into contracts for the procurement of two
generators and the connection to the grid. Planning permission was received
for the cable installation in July. We have been informed by the distribution
network operator that energisation of the grid connection will not be
completed in 2025. Whilst we are working with the operator to expedite this.
we expect the project go live date to be delayed into 2026.
Reserves and resources
CPR
In February 2025, Star Energy announced the publication of the full and final
results of the Competent Person's Report (CPR) by DeGolyer & MacNaughton
(D&M), a leading international reserves and resources auditor.
The report comprised an independent evaluation of Star Energy's conventional
oil and gas interests as of 31 December 2024. The full report can be found
here:
https://www.starenergygroupplc.com/investors/reports-publications-presentations
(https://www.starenergygroupplc.com/investors/reports-publications-presentations)
.
Net Reserves & Contingent Resources as at 31 December 2024 (MMboe)
1P 2P 2C
Reserves & Resources as at 31 December 2023 11.71 17.47 18.59
Production during the period (0.67) (0.67) -
Additions & revisions during the period (0.87) (1.49) (2.30)
Reserves & Resources as at 31 December 2024 10.17 15.31 16.29
*Oil price assumption of c.$72/bbl for 5 years, then inflated at 2-3% p.a.
from 2029 to 2054
**The production in the reserves movement table incorporates production at the
following sites: Albury, Beckingham, Bletchingley, Bothamsall, Cold Hanworth,
Corringham, East Glentworth, Egmanton, Glentworth, Goodworth, Horndean, Long
Clawson, Palmers Wood, Scampton North, Singleton, Stockbridge and Welton.
The report values our conventional assets at $188 million (2023: $235 million)
on a 2P NPV10 basis.
Licence Rationalisation
We have rationalised our portfolio of exploration licences, relinquishing
early-stage exploration and shale licences whilst retaining a core exploration
acreage adjacent to our existing operations in the East Midlands. This
exploration acreage not only holds conventional oil and gas prospects but also
overlies a nationally significant shale gas resource. Seismic data, well data
and widespread detailed surface constraints mapping shows that this acreage is
geologically significantly more structurally simple than other UK shale basins
and offers far fewer surface constraints.
During 2024, we also re-organised and simplified our operating licence
structure and we have seen the results of this in 2025 with reduced costs and
a lower administrative burden.
Geothermal Development
UK Projects
We have completed the detailed feasibility study for our project at Salisbury
District Hospital. This included the reprocessing of 700km of legacy 2D
seismic data, the acquisition of four new seismic lines and the development of
an extensive geological model at the hospital site. The study confirmed the
presence of a viable geothermal reservoir. In parallel, pre application for
planning and regulators consents have been completed and a conceptual well
design developed. This work has concluded with a commercial assessment on the
project and we have provided indicative heads of terms for supply of that heat
to the hospital under a long-term thermal purchase agreement (TPA).
We completed the detailed feasibility study for our Wythenshawe Hospital
project. This included reprocessing of seismic, pre applications, conceptual
well designs and commercial assessment. The study identified two viable
geothermal targets and we provided indicative terms for supply from both under
long-term TPA. We expect to commence the planning and permitting phase of the
project in Q4. A seismic acquisition programme for the project is currently
under design and will be executed in the next phase.
Croatia Projects
Following the acquisition of the Ernestinovo licence in August 2023, the
exploration licence commitment was satisfied in March 2024. The exploitation
field within the Ernestinovo licence has been established and the conceptual
field development plan is being compiled to be submitted to the Croatian
Ministry of Economy with the aim of progressing the licence to its
exploitation phase in Q1 2026.
The Sjece and Pcelic licences were awarded in October 2023. Magnetotelluric
data on both Sječe and Pčelić exploration licences have been acquired and a
technical de-risking of the licences is being undertaken to enable phased
development. All our Croatian licences are in areas where substantial offset
data sets are available from previous conventional oil and gas drilling
activities.
Alongside this, our technical teams are at an advanced stage of consolidating
all existing and new data for each of our three licences in Croatia. 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
commercial development of the licences. Preliminary conclusions point to good
prospects within our Croatian portfolio, with high temperatures recorded in
existing wells comparable with other Croatian geothermal reservoirs and the
potential is also supported by results from nearby drilling and testing of
similar (geological and depth-wise) geothermal well at Podravska Slatina by
the Energia Naturalis (ENNA) Group. Acquisition and interpretation of
Magnetotelluric data has aided definition of the extent of the geothermal
deposits and, together with additional subsurface interpretations, a number of
potential well targets in all licenses have been identified. The analysis and
ranking of these targets are currently underway, and we expect to complete
this work by year end. Following this, work will then progress to mature these
opportunities and develop well proposals and drilling programs.
Financial review
Income Statement
The Group generated revenue of £18.3 million in the first six months of 2025
from sales of 339,635 barrels of oil and 4,129 Mwh of electricity. (H1 2024:
revenue of £23.2 million from sales of 355,800 barrels of oil, 3,644 Mwh of
electricity and 171,542 therms of gas). The reduction in revenues was
primarily driven by lower oil prices and a weaker US dollar, with Brent prices
averaging $71.7/bbl in H1 2025 compared to $84.1/bbl during H1 2024 and the
USD/GBP rate averaging $1.31/£1 compared to $1.27/£1 in H1 2024.
Adjusted EBITDA for H1 2025 was £4.5 million (H1 2024: £6.5 million), of
which £5.5 million (H1 2024: £8.9 million) related to our oil and gas
operations and £(1.0) million (H1 2024: £(2.4) million) related to
geothermal activities.
The loss after tax from continuing activities was £4.1 million (H1 2024:
£2.5 million) and the main factors explaining the movements between H1 2025
and H1 2024 were as follows:
· Revenues reduced to £18.3 million (H1 2024: £23.2 million) primarily
reflecting lower oil prices and a weaker US dollar. Sales volumes also reduced
from 1,995 boe/d to 1,901 boe/d, reflecting the cessation of gas sales from
our Albury facility and planned downtime for workovers at a number of sites;
· Depletion, depreciation and amortisation (DD&A) increased to £3.6
million (H1 2024: £2.9 million) as a result of a reduction in the Group's
estimated proven and probable reserves as at 1 January 2025 as noted in our
2024 Annual Report;
· We saw a small increase in operating costs to £10.8 million (H1 2024:
£10.4 million) mainly due to an increase in workover activity, but have been
able to offset inflationary increases through savings in a number of areas;
· We generated material savings in administrative expenses which reduced
to £2.5 million (H1 2024: £4.1 million). £0.8 million of savings were
realised through a cost cutting exercise with the lower cost base continuing
into the future. The balance of the savings related to non-recurring costs in
2024 relating to the refinancing of the Group's borrowings and other corporate
projects;
· Research and non-capitalised development costs were £0.3 million (H1
2024: £1.8 million). Higher expenditure in H1 2024 reflected the cost of
re-entering and testing a well on the Ernestinovo licence to fulfil the
licence commitments;
· We completed the sale of our Holybourne site in the period which
resulted in a net gain on disposal of £4.5 million. H1 2024 included a charge
of £2.0 million in connection with preparing the Holybourne site for sale;
· No significant write off of exploration and evaluation assets in the
current period; H1 2024 included the write off of exploration and evaluation
assets of £1.8 million mainly as a result of relinquishing the PEDL 235
(Godley Bridge) licence;
· H1 2024 included the impairment of development costs relating to the
Stoke-on-Trent geothermal project. No such impairment charge recognised in the
current period;
· We recognised a gain of £0.5 million from the write-off of contingent
consideration payable relating to the acquisition of GT Energy UK Limited (H1
2024: £2.3 million) as the related milestones will not be achieved. The full
amount of contingent consideration related to the acquisition has now been
extinguished;
· We recognised a gain of £1.0 million on our oil hedging programme (H1
2024: loss of £0.1 million);
· Net finance costs increased to £3.0 million (H1 2024: £2.4 million)
mainly due to increase in foreign exchange loss arising from movements in
USD/GBP and Euro/GBP exchange rates; and
· A tax charge of £8.4 million (H1 2024: tax credit of £1.7 million)
was recognised in the period. The charge included current taxes of £0.5
million relating to the estimated EPL charge on profits for the period, and a
deferred tax charge of £8.0 million due to lower forecast oil prices and an
extension of the EPL regime leading to a reduction in the amount of recognised
tax losses.
Cash Flow
Net cash generated from operations before working capital movements and tax
increased to £4.8 million for the period (H1 2024: £4.4 million) as the
impact of reduced cash outflows from lower administrative expenses, research
and non-capitalised geothermal development costs and other expenses in the
period more than offset the impact of reduced cash inflows from a decline in
revenues.
The Group invested £2.0 million across its asset base during the period (H1
2024: £3.0 million) primarily on the Singleton gas-to-wire project as well as
a number of other projects carried out to increase production from existing
wells and to offset field declines. The Group received £6.3 million from the
sale of the Holybourne site in the period.
The Group repaid £5.6 million (€6.7 million) to fully settle facility A of
its loan facility in line with its contractual maturity date (H1 2024:
drawdown of £6.1 million (€7.1 million) under the loan facility and
repayment of £5.5 million ($7.0 million) to fully settle the RBL facility
with the Bank of Montreal). Interest paid during the period was £0.7 million
(H1 2024: £0.2 million). Repayments made in respect of lease obligations were
£1.2 million (H1 2024: £0.6 million).
The Group paid £1.0 million in settlement of its EPL liability for the 2023
tax year.
Cash and cash equivalents were £4.3 million at the end of the period (31
December 2024: £4.7 million).
Balance Sheet
The Group had net assets of £38.5 million at 30 June 2025 (31 December 2024:
£42.6 million).
Property, plant and equipment reduced by £3.3 million due to a DD&A
charge of £3.0 million, disposals of £1.9 million and a reduction in value
of decommissioning assets of £0.3 million, partially offset by capital
expenditure of £2.0 million.
The deferred tax asset reduced by £8.0 million mainly due to a change in
forecast utilisation of available tax losses and impact of extension of the
period of EPL.
Derivative financial assets increased by £0.8 million due to an unrealised
gain on hedges.
Trade and other receivables reduced by £1.7 million mainly due to a decrease
in trade receivables of £0.9 million and the settlement of a convertible loan
note of £0.4 million by the minority shareholder in A14 Energy Limited. Trade
and other payables reduced by £2.1 million mainly due to the timing of
expenditure.
The Group's borrowings reduced by £5.2 million as we repaid facility A in
June 2025. Lease liabilities reduced by £0.7 million due to the timing of
payments and right-of-use assets reduced by £0.4 million. The provision for
decommissioning increased by £0.7 million due to the unwinding of discount by
£1.3 million, partially offset by utilisation of £0.3 million and a
reassessment of provision of £0.3 million.
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 cash
operating costs. 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 Interim Report to better understand the Group's
performance in the period in comparison to previous periods and to industry
peers.
Net Debt
Net debt, being borrowings excluding capitalised fees less cash and cash
equivalents, decreased from the end of the previous year to £2.7 million at
30 June 2025 (31 December 2024: £7.5 million; 30 June 2024: £1.9 million).
The Group's definition of net debt does not include the Group's lease
liabilities.
Six months ended Six months ended Year ended
30 June 2025 30 June 2024 31 December 2024
£m £m £m
Debt (nominal value excluding capitalised expenses) (7.0) (6.1) (12.2)
Cash and cash equivalents (excluding restricted cash) 4.3 4.2 4.7
Net debt (2.7) (1.9) (7.5)
Adjusted EBITDA
Adjusted EBITDA includes adjustments in relation to non-cash items such as
share-based payment charges and unrealised gain/loss on hedges together with
other one-off exceptional items, and after deducting lease rentals capitalised
under IFRS 16.
Six months ended Six months ended Year ended 31 December 2024
30 June 2025 30 June 2024 (restated)
£m £m £m
Profit/(loss) before tax 4.4 (4.2) (4.5)
Net finance costs 3.0 2.4 4.8
Depletion, depreciation & amortisation 3.6 2.9 6.5
Impairment of development costs - 4.3 4.3
Impairment of exploration and evaluation assets - 1.8 1.9
Changes in fair value of contingent consideration (0.5) (2.3) (2.3)
EBITDA 10.5 4.9 10.7
Lease rentals capitalised under IFRS 16 (1.0) (0.8) (1.9)
Profit on sale of property, plant and equipment (4.5) - -
Other expenses - 2.0 2.0
Share-based payment charges 0.1 0.1 0.2
Unrealised (gain)/loss on hedges (0.8) 0.1 (0.4)
Redundancy costs 0.2 0.2 0.5
Adjusted EBITDA 4.5 6.5 11.1
Related to oil and gas business segment 5.5 8.9 15.1
Related to Geothermal business segment (1.0) (2.4) (4.0)
Underlying cash operating costs
Six months ended Six months ended Year ended 31 December 2024
30 June 2025 30 June 2024
£m £m £m
Other cost of sales* 10.8 10.4 22.3
Lease rentals capitalised under IFRS 16 1.0 0.8 1.9
Underlying operating costs 11.8 11.2 24.2
* this represents total cost of sales less depletion, depreciation and
amortisation.
Principal risks and uncertainties
The Group constantly monitors the Group's risk exposures and management
reports to the Audit Committee and the Board on a regular basis. The Audit
Committee receives and reviews these reports and focuses on ensuring that the
effective systems of internal financial and non-financial controls including
the management of risk are maintained. The results of this work are reported
to the Board which in turn performs its own review and assessment.
The principal risks for the Group remain as previously detailed on pages 22-23
of the 2024 Annual Report and Accounts and can be summarised as:
· Political risk such as change in Government or the effect of local or
national referendums which can result in changes to the regulatory or fiscal
regime;
· Strategy, and its execution, fails to meet shareholder expectations;
· Climate change risks that causes changes to laws, regulations,
policies, obligations and social attitudes relating to the transition to a
lower carbon economy which could have a cost impact or reduced demand for
hydrocarbons for the Group and could impact our Strategy;
· Risk of reduction in appetite for low carbon heat solutions;
· Cyber security risk that gives exposure to a serious cyber-attack
which could affect the confidentiality of data, the availability of critical
business information and cause disruption to our operations;
· Planning, environmental, licensing and other permitting risks
associated with operations and in particular, with drilling and production
operations;
· Oil or gas production, as no guarantee can be given that they can be
produced in the anticipated quantities from any or all of the Group's assets
or that oil or gas can be delivered economically;
· Risk of delays in project delivery, higher cost of project delivery
and lower than forecast output of projects delivered;
· Failure to achieve targeted geothermal production rates;
· Loss of key staff;
· Pandemic that impacts the ability to operate the business
effectively;
· Oil market price risk through variations in the wholesale price in
the context of the production from oil fields it owns and operates;
· Electricity market price risk through variations in the wholesale
price in the context of its future production volumes;
· Exchange rate risk through its major source of revenue being priced
in US$ and its borrowings being priced in Euros while most of the Group's
operating and G&A costs are denominated in UK pounds sterling;
· Liquidity risk; and
· Capital risk resulting from its capital structure, including
operating within the covenants of its finance facility.
Going concern
The Group continues to closely monitor and manage its liquidity risks. 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 uncertain global economic outlook has
reduced crude oil prices in the first half of 2025, with volatility in oil
prices and foreign exchange rates likely to continue.
The focus of the Group in 2025 has been to strengthen our balance sheet and
improve our resilience to oil price volatility. We have generated positive
operating cashflows in H1 2025 as a result of stable production and a
continued effort to minimise operating costs. We have also carried out a
reorganisation in 2024 resulting in a material reduction in general and
administrative costs in 2025. Our €25 million finance facility, of which
€10.2 million remains undrawn, and the sale of non-core land with the
proceeds of £6.3 million being received in April 2025, further improve 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 152,800 barrels hedged for the second
half of 2025 and first quarter of 2026 using swaps at an average price of
$72.9/bbl. We have additionally created some downside protection for 237,800
bbls with a three-way put/call options for H2 2025 and for 2026. We have also
put in place USD/GBP foreign exchange hedges for $0.5 million/month at a rate
of $1.227/£1 for the remainder of 2025
The Group's base case cash flow forecast was run with average oil prices of
$66/bbl until the end of H1 2026, $68/bbl for H2 2026, $70/bbl for Q1 2027,
and foreign exchange rates of an average $1.35/£1 for the remainder of 2025,
$1.33/£1 for 2026, and $1.30/£ for Q1 2027. In this base case scenario, our
forecasts show that the Group will have 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 $60/bbl in Q4 2025 and $62/bbl in 2026, before
recovering to $65/bbl by Q1 2027. In this downside case management has assumed
foreign exchange rates of an average $1.35/£1 for the remainder of the going
concern period. Our downside case also included a reduction in production of
5% throughout the going concern period. In the event of a downside scenario,
management could take mitigating actions including delaying capital
expenditure and reducing costs, in order 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 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.
Statement of Directors' responsibilities
The Directors confirm that these Condensed Interim Consolidated Financial
Statements have been prepared in accordance with UK-adopted International
Accounting Standard 34, 'Interim Financial Reporting' ("IAS 34") and the AIM
Rules for Companies; and these Unaudited Interim results include:
· a fair review of the information required (i.e., an indication of
important events and their impact during the first six months and a
description of the principal risks and uncertainties for the remaining six
months of the financial year); and
· a fair review of the information required on related party
transactions.
By order of the Board,
Ross Glover
Chief Executive Officer
16 September 2025
Condensed Interim Consolidated Income Statement
Notes Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2025 30 June 2024 31 December 2024
£000 £000 £000
Revenue 4 18,297 23,230 43,651
Cost of sales:
Depletion, depreciation and amortisation (3,603) (2,886) (6,472)
Other costs of sales (10,775) (10,371) (22,318)
(14,378) (13,257) (28,790)
3,919 9,973 14,861
Gross profit
Administrative expenses (2,543) (4,075) (7,422)
Research and non-capitalised development costs (303) (1,799) (1,973)
Impairment of development costs 9 - (4,259) (4,259)
Exploration and evaluation assets impaired 9 (26) (1,849) (1,854)
Gain/(loss) on derivative financial instruments 1,333 (74) 737
Other expense 7 - (2,000) (2,000)
Other income 7 4,540 3 3
Operating profit/(loss) 6,920 (4,080) (1,907)
Finance costs 5 (3,040) (2,396) (4,805)
Change in fair value of contingent consideration 12 480 2,251* 2,251
Profit/(loss) before tax 4,360 (4,225) (4,461)
Income tax 6 (8,429) 1,727 (8,133)
Loss after tax (4,069) (2,498) (12,594)
Attributable to:
Owners of the Parent Company (3,922) (1,534) (11,295)
Non-controlling interest (147) (964) (1,299)
(4,069) (2,498) (12,594)
Loss per share attributable to equity shareholders: 8 (2.97p) (1.17p) (8.74p)
Basic loss per share
Diluted loss per share 8 (2.97p) (1.17p) (8.74p)
Condensed Interim Consolidated Statement of Comprehensive Income
Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2025 30 June 2024 31 December 2024
£000 £000 £000
Loss for the period/year (4,069) (2,498) (12,594)
Other comprehensive income for the period/year:
Items that may be reclassified subsequently to profit or loss:
Foreign exchange differences on translation of foreign operations (181) 24 117
Total comprehensive loss for the period/year (4,250) (2,474) (12,477)
Total comprehensive loss attributable to:
Owners of the Parent Company (4,086) (1,527) (11,181)
Non-controlling interest (164) (947) (1,296)
(4,250) (2,474) (12,477)
* See note 17 for explanation of reclassification of this balance.
Condensed Interim Consolidated Balance Sheet
Notes Unaudited Unaudited Audited
at 30 June 2025 at 30 June 2024 at 31 December 2024
£000 £000 £000
ASSETS
Non-current assets
Intangible assets 9 7,899 7,811 7,736
Property, plant and equipment 10 67,402 72,129 70,657
Right-of-use assets 6,872 7,621 7,253
Restricted cash 4,282 - 4,282
Deferred tax asset 6 23,070 40,592 31,054
109,525 128,153 120,982
Current assets
Inventories 1,450 1,552 1,497
Trade and other receivables 4,663 5,876 6,381
Cash and cash equivalents 13 4,277 4,199 4,708
Derivative financial instruments 11 1,197 - 398
11,587 11,627 12,984
Total assets 121,112 139,780 133,966
LIABILITIES
Current liabilities
Trade and other payables (4,621) (8,017) (6,731)
Corporation tax payable 6 (2,569) (1,099) (3,073)
Borrowings 13 (1,158) (5,483) (6,488)
Derivative financial instruments 11 - (74) -
Lease liabilities (973) (1,054) (1,145)
Provisions 12 (826) (1,858) (1,335)
(10,147) (17,585) (18,772)
Non-current liabilities
Borrowings 13 (5,332) - (5,246)
Other payables (69) - (440)
Corporation tax payable 6 - (1,664) -
Lease liabilities (6,337) (7,334) (6,830)
Provisions 12 (60,729) (60,628) (60,035)
(72,467) (69,626) (72,551)
Total liabilities (82,614) (87,211) (91,323)
Net assets 38,498 52,569 42,643
Notes Unaudited Unaudited Audited
at 30 June 2025 at 30 June 2024 at 31 December 2024
£000 £000 £000
EQUITY
Capital and reserves
Called up share capital 14 30,334 30,334 30,334
Share premium account 14 103,278 103,218 103,248
Foreign currency translation reserve 3,768 3,822 3,929
Other reserves 38,587 38,465 38,512
Accumulated deficit (136,684) (122,570) (132,331)
Equity attributable to owners of the Company 39,283 53,269 43,692
Non-controlling interest (785) (700) (1,049)
Total equity 38,498 52,569 42,643
Condensed Interim Consolidated Statement of Changes in Equity
Called up Share Foreign Other Accumulated deficit Equity attributable to owners of the Company Non-controlling interest £000 Total equity
share premium currency reserves** £000 £000 £000
capital account translation £000
£000 £000 reserve*
£000
At 1 January 2024 (audited) 30,334 103,189 3,815 38,324 (121,036) 54,626 247 54,873
Loss for the period - - - - (1,534) (1,534) (964) (2,498)
Share options issued under the employee share plan - - - 141 - 141 - 141
Issue of shares (note 14) - 29 - - - 29 - 29
Currency translation adjustments - - 7 - - 7 17 24
At 30 June 2024 (unaudited) 30,334 103,218 3,822 38,465 (122,570) 53,269 (700) 52,569
Loss for the period - - - - (9,761) (9,761) (335) (10,096)
Share options issued under the employee share plan - - - 47 - 47 - 47
Issue of shares (note 14) - 30 - - - 30 - 30
Currency translation adjustments - - 107 - - 107 (14) 93
At 31 December 2024 (audited) 30,334 103,248 3,929 38,512 (132,331) 43,692 (1,049) 42,643
Loss for the period - - - - (3,922) (3,922) (147) (4,069)
Acquisition of non-controlling interest without a change in control (note 15) - - 3 - (431) (428) 428 -
Share options issued under the employee share plan - - - 75 - 75 - 75
Issue of shares (note 14) - 30 - - - 30 - 30
Currency translation adjustments - - (164) - - (164) (17) (181)
At 30 June 2025 (unaudited) 30,334 103,278 3,768 38,587 (136,684) 39,283 (785) 38,498
* The foreign currency translation reserve includes an
amount of £3,799 thousand (31 December 2024: £3,799 thousand, 30 June 2024:
£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.
Condensed Interim Consolidated Cash Flow Statement
Notes Unaudited Unaudited Audited
6 months ended 6 months ended year
30 June 30 June ended
2025 2024 31 December
£000 £000 2024
£000
Cash flows from operating activities:
Profit/(loss) before tax 4,360 (4,225) (4,461)
Depletion, depreciation and amortisation 3,626 2,909 6,517
Abandonment costs/other provisions utilised or released (508) (734) (1,672)
Share-based payment charge 94 141 195
Exploration and evaluation assets impaired 9 26 1,849 1,854
Impairment of development costs 9 - 4,259 4,259
Change in fair value of contingent consideration 12 (480) (2,251) (2,251)
Unrealised (gain)/loss on derivative financial instruments (799) 74 (398)
Gain on sale of fixed assets (4,540) (3) (3)
Finance costs 5 3,040 2,396 4,805
Operating cash flows before working capital movements 4,819 4,415 8,845
Decrease/(increase) in trade and other receivables and other financial assets 1,993 473 (1,397)
(Decrease) in trade and other payables (2,547) (751) (1,334)
(Increase) in restricted cash - - (3,872)
Decrease/(increase) in inventories 47 (30) 25
Cash generated from operating activities 4,312 4,107 2,267
Tax paid (964) - -
Net cash generated from operating activities 3,348 4,107 2,267
Cash flows from investing activities:
Purchase of intangible exploration and evaluation assets (86) (118) (67)
Purchase of property, plant and equipment (1,956) (2,881) (5,579)
Purchase of intangible development assets - (29) (30)
Proceeds from disposal of property, plant and equipment 6,390 3 3
Net cash generated from/(used in) investing activities 4,348 (3,025) (5,673)
Cash flows from financing activities:
Cash proceeds from issue of ordinary share capital 14 14 13 28
Drawdown on finance facility 13 - 6,110 12,530
Repayment of finance facility 13 (5,631) - -
Repayment of Reserves Based Lending facility 13 - (5,541) (5,541)
Transaction costs related to loan refinancing 13 - (626) (610)
Repayment of principal portion of lease liabilities (854) (222) (887)
Repayment of interest on lease liabilities (326) (344) (709)
Interest paid 13 (694) (154) (493)
Net cash (used in)/generated from financing activities (7,491) (764) 4,318
Net increase in cash and cash equivalents during the period/year 205 318 912
Net foreign exchange differences (636) 26 (59)
Cash and cash equivalents at the beginning of the period/year 4,708 3,855 3,855
Cash and cash equivalents at the end of the period/year 13 4,277 4,199 4,708
Notes to the Unaudited Condensed Interim Consolidated Financial Statements
1 Corporate information
The condensed interim consolidated financial statements of Star Energy Group
plc and its subsidiaries (the Group) for the six months ended 30 June 2025,
which are unaudited, were authorised for issue in accordance with a resolution
of the Directors on 16 September 2025. Star Energy Group plc is a public
limited company incorporated in the United Kingdom and registered in England
and Wales and 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.
2 Accounting policies
Basis of preparation
These unaudited condensed interim consolidated financial statements for the
six months ended 30 June 2025 have been prepared in accordance with UK-adopted
International Accounting Standard 34, 'Interim Financial Reporting' ("IAS 34")
and the AIM Rules for Companies. The unaudited condensed interim consolidated
financial statements should be read in conjunction with the consolidated
financial statements for the year ended 31 December 2024. The annual financial
statements of Star Energy Group plc are prepared in accordance with UK-adopted
International Accounting Standards.
The financial information contained in this document does not constitute
statutory accounts as defined by Section 434 of the Companies Act 2006
(England & Wales). The financial information as at 31 December 2024 is
based on the statutory accounts for the year ended 31 December 2024. A copy
of the statutory accounts for that year, has been delivered to the Registrar
of Companies and is available on the Company's website at
www.starenergygroupplc.com. The auditors' report in accordance with Chapter 3
Part 16 of the Companies Act 2006 in relation to those accounts was
unqualified, did not draw attention to any matters by way of emphasis and did
not contain a statement under section 498(2) or (3) of the Companies Act 2006.
The accounting policies adopted are consistent with those of the previous
financial year and corresponding interim reporting period, except for the
adoption of the new and amended standards and interpretations discussed below.
Prior period numbers have been reclassified, where necessary, to conform to
the current period presentation.
Going concern
The Group continues to closely monitor and manage its liquidity risks. 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 uncertain global economic outlook has
reduced crude oil prices in the first half of 2025, with volatility in oil
prices and foreign exchange rates likely to continue.
The focus of the Group in 2025 has been to strengthen our balance sheet and
improve our resilience to oil price volatility. We have generated positive
operating cashflows in H1 2025 as a result of stable production and a
continued effort to minimise operating costs. We have also carried out a
reorganisation in 2024 resulting in a material reduction in general and
administrative costs in 2025. Our €25 million finance facility, of which
€10.2 million remains undrawn, and the sale of non-core land with the
proceeds of £6.3 million being received in April 2025, further improve 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 152,800 barrels hedged for the second
half of 2025 and first quarter of 2026 using swaps at an average price of
$72.9/bbl. We have additionally created some downside protection for 237,800
bbls with a three-way put/call options for H2 2025 and for 2026. We have also
put in place USD/GBP foreign exchange hedges for $0.5 million/month at a rate
of $1.227/£1 for the remainder of 2025
The Group's base case cash flow forecast was run with average oil prices of
$66/bbl until the end of H1 2026, $68/bbl for H2 2026, $70/bbl for Q1 2027,
and foreign exchange rates of an average $1.35/£1 for the remainder of 2025,
$1.33/£1 for 2026, and $1.30/£ for Q1 2027. In this base case scenario, our
forecasts show that the Group will have 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 $60/bbl in Q4 2025 and $62/bbl in 2026, before
recovering to $65/bbl by Q1 2027. In this downside case management has assumed
foreign exchange rates of an average $1.35/£1 for the remainder of the going
concern period. Our downside case also included a reduction in production of
5% throughout the going concern period. In the event of a downside scenario,
management could take mitigating actions including delaying capital
expenditure and reducing costs, in order 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 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.
New and amended standards and interpretations
During the period, the Group adopted the following new and amended IFRSs for
the first time for their reporting period commencing 1 January 2025:
Amendments to IAS 21 Lack of exchangeability
The above amendment to IAS 21 did not have a material impact on the financial
statements of the Group. There are no other standards that are not yet
effective and that would be expected to have a material impact on the entity
in the current or future reporting periods, with the exception of 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 newly issued standard on our
future financial statements.
Estimates and judgements
The preparation of the unaudited condensed interim consolidated financial
statements requires management to make judgements, estimates and assumptions
that affect the application of accounting policies and the reported amounts of
assets, liabilities, income and expense. Actual results may differ from these
estimates.
In preparing these unaudited condensed interim consolidated financial
statements, 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 applied to the consolidated financial statements for the
year ended 31 December 2024.
Financial risk management
The Group's activities expose it to a variety of financial risks; market risk
(including interest rate, commodity price and foreign currency risks), credit
risk and liquidity risk.
The unaudited condensed interim consolidated financial statements do not
include financial risk management information and disclosures required in the
annual financial statements; accordingly, the unaudited condensed interim
consolidated financial statements should be read in conjunction with the
Group's annual financial statements as at 31 December 2024.
3 Basis of consolidation
The unaudited condensed interim consolidated financial statements present the
results of Star Energy Group plc and its subsidiaries as if they formed a
single entity. The financial information of subsidiaries used in the
preparation of these unaudited condensed interim consolidated financial
statements is based on consistent accounting policies to those of the Company.
All intercompany transactions and balances between Group companies, including
unrealised profits/losses arising from them, are eliminated in full. Where
shares are issued to an Employee Benefit Trust, and the Company is the
sponsoring entity, it is treated as an extension of the entity.
4 Revenue
The Group derives revenue solely within the United Kingdom from the transfer
of control over 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:
Unaudited Unaudited Audited
6 months ended 6 months ended year
30 June 2025 30 June 2024 ended
31 December 2024
£000 £000 £000
Oil sales 17,796 22,861 42,794
Electricity sales 501 246 550
Gas sales - 123 249
Other - - 58
Revenue for the period/year 18,297 23,230 43,651
5 Finance costs
Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2025 30 June 2024 31 December 2024
£000 £000 £000
Finance costs:
Interest on borrowings (595) (382) (817)
Amortisation of finance fees on borrowings (65) (183) (226)
Net foreign exchange loss (670) (62) (84)
Unwinding of discount on decommissioning provision (note 12) (1,309) (1,221) (2,537)
Interest charge on lease liability (326) (344) (709)
Other interest payable (75) (204) (432)
Finance costs for the period/year (3,040) (2,396) (4,805)
6 Tax on profit/(loss) on ordinary activities
The Group calculates the period income tax expense using the UK corporation
tax rate that would be applicable to expected total annual earnings for the 12
months ending 31 December 2025. The majority of the Group's profits are
generated by "ring-fence" business which attract UK corporation tax and
supplementary charges at a combined average rate of 40% (six months ended 30
June 2024: 40%), in addition to the Energy Profit Levy (EPL) with a rate of
38% for the period (six months ended 30 June 2024: 35%). The tax charge for
the period comprises deferred tax charge of £8.0 million (six month ended 30
June 2024: deferred tax credit of £3.4 million) principally due to reduction
in the amount of recognised tax losses due to lower forecast oil prices and an
extension of the EPL regime, and a current tax charge of £0.5 million in
respect of the EPL (six months ended 30 June 2024: £1.7 million).
The major components of income tax expense in the unaudited condensed interim
consolidated income statement are:
Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2025 30 June 2024 31 December 2024
£000 £000 £000
UK corporation tax
Charge on profit/(loss) for the period/year 460 1,664 2,110
Credit in relation to prior periods - - (136)
Total current tax charge 460 1,664 1,974
Deferred tax
Charge/(credit) relating to the origination or reversal of temporary 7,984 (3,558) 6,570
differences
Credit due to rate changes - - (1,070)
(Credit)/charge in relation to prior periods (15) 167 659
Total deferred tax charge/(credit) 7,969 (3,391) 6,159
Tax charge/(credit) on profit/(loss) on ordinary activities for the 8,429 (1,727) 8,133
period/year
A deferred tax asset of £23.1 million (30 June 2024: £40.6 million, 31
December 2024: £31.1 million) has been recognised in respect of tax losses
and other temporary differences where the Directors believe that it is
probable that these assets will be recovered based on estimated taxable profit
forecasts.
Corporation tax payable of £2.6 million (30 June 2024: £2.8 million, 31
December 2024: £3.1 million) has been recognised in respect of the EPL. Tax
paid in the period was £1.0 million (30 June 2024: £nil, 31 December 2024:
£nil).
The Group has gross total tax losses and similar attributes carried forward of
£367.6 million (30 June 2024: £361.6 million, 31 December 2024: £367.8
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 are offsetting deferred tax liabilities. Such recognised
tax losses include £75.0 million (30 June 2024: £104.8 million, 31 December
2024: £85.0 million) of ringfence corporation tax losses which will be
recovered at 30% of future taxable profits, £63.0 million (30 June 2024:
£90.4 million, 31 December 2024: £70.2 million) of supplementary charge tax
losses which will be recovered at 10% of future taxable profits, £3.5 million
(30 June 2024: £4.8 million, 31 December 2024: £4.1 million) of losses
arising under the EPL regime which will be recovered at 38% of future taxable
profits and £3.2 million (30 June 2024: £4.6 million, 31 December 2024:
£3.2 million) of non-ringfence corporation tax losses which will be recovered
at 25% of future taxable profits.
7 Other income/expense
Other income of £4.5 million primarily relates to gain on sale of the land at
the decommissioned Holybourne processing facility. The site was sold for a
cash consideration of £6.3 million in April 2025. Other expense of £2.0
million in the period to 30 June 2024 related to costs incurred in connection
with the sale.
8 Earnings per share (EPS)
Basic EPS amounts are based on the loss for the period after taxation
attributable to the ordinary equity holders of the Parent Company of £3.9
million and the weighted average number of ordinary shares outstanding during
the period of 132.1 million.
Diluted EPS amounts are based on the loss for the period/year after taxation
attributable to the ordinary equity holders of the Parent Company and the
weighted average number of shares outstanding during the period/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 30 June 2025, there are 6.3 million potentially dilutive employee share
options. These were not included in the calculation at 30 June 2025, as their
conversion to ordinary shares would have decreased the loss per share.
9 Intangible assets
Exploration and evaluation assets Development costs Goodwill Total
£'000 £'000 £'000 £'000
Cost
At 1 January 2024 (audited) 5,655 6,972 1,196 13,823
Additions 147 30 - 177
Exchange differences - (56) (25) (81)
Impairment (1,849) (4,259) - (6,108)
At 30 June 2024 (unaudited) 3,953 2,687 1,171 7,811
Additions 29 - - 29
Exchange differences - (61) (30) (91)
Transfer to PPE (8) - - (8)
Impairment (5) - - (5)
At 31 December 2024 (audited) 3,969 2,626 1,141 7,736
Additions 59 - - 59
Exchange differences - 88 42 130
Impairment (26) - - (26)
At 30 June 2025 (unaudited) 4,002 2,714 1,183 7,899
Exploration and evaluation assets
Exploration costs impaired in the period to 30 June 2025 were £0.03 million
(6 months to 30 June 2024: £1.8 million, year ended 31 December 2024: £1.9
million) representing costs of early-stage oil and gas projects where it was
assessed that there was no further development prospect.
The Group has £4.0 million (six months ended 30 June 2024: £4.0 million,
year ended 31 December 2024: £4.0 million) of capitalised exploration
expenditure which relates to our oil and gas assets including PL 240.
Management 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 an impairment.
Goodwill
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 licences (Ernestinovo, Sječe and Pčelić) and the UK geothermal
business. The carrying amount of goodwill arose on the acquisition of an
interest in A14 Energy Limited ("A14 Energy") in 2023 and is allocated to the
following CGUs:
Unaudited Unaudited Audited
at 30 June 2025 at 30 June 2024 at 31 December 2024
£000 £000 £000
Sječe licence 364 360 352
Pčelić licence 364 360 351
Ernestinovo licence 455 451 438
1,183 1,171 1,141
The Group tests goodwill for impairment annually or more frequently if there
are indications that goodwill might be impaired. At 30 June 2025, management
reviewed the carrying value of the Sječe and Pčelić licence CGUs and
assessed them for impairment. The recoverable amount calculated was higher
than the carrying value, hence no impairment charge was recognised against the
goodwill allocated to these CGUs .
Development costs
The carrying amount of development costs is split between CGUs as follows:
Unaudited Unaudited Audited
at 30 June 2025 at 30 June at 31 December
£000 2024 2024
£000 £000
UK geothermal business 186 186 186
Ernestinovo licence 2,528 2,501 2,440
2,714 2,687 2,626
The costs allocated to the UK geothermal business CGU primarily relate to the
design and development of deep geothermal heat projects in the United Kingdom
and was recognised as part of the acquisition of GT Energy UK Limited in 2020.
The costs associated with the Ernestinovo licence relate to the fair value of
assets acquired as part of the A14 Energy acquisition. 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 Ernestinovo
exploration licence.
The Group tests intangible assets not yet ready for use for impairment
annually or more frequently if there are indications that the asset might be
impaired. At 30 June 2025, management reviewed the carrying value of the
Ernestinovo licence CGU and assessed it for impairment. The recoverable amount
calculated was higher than the carrying value of the CGU, hence no impairment
charge was recognised against capitalised development cost or allocated
goodwill.
10 Property, plant and equipment
Unaudited Unaudited Audited
at 30 June 2025 at 30 June 2024 at 31 December 2024
£'000 £'000 £'000
Oil and gas assets Other property, plant and equipment Total Oil and gas assets Other property, plant and equipment Total Oil and gas assets Other property, plant and equipment Total
Cost
At 1 January 228,879 1,709 230,588 226,888 1,734 228,622 226,888 1,734 228,622
Additions 1,959 - 1,959 1,692 - 1,692 4,812 - 4,812
Transfer from exploration and evaluation assets - - - - - - 8 - 8
Disposals/write offs (5,335) (83) (5,418) - (29) (29) - (25) (25)
Changes in decommissioning (2,829) - (2,829)
(336) - (336) (1,217) - (1,217)
At 30 June/31 December 225,167 1,626 226,793 227,363 1,705 229,068 228,879 1,709 230,588
Accumulated Depreciation, Depletion and Impairment
At 1 January 159,297 634 159,931 154,004 624 154,628 154,004 624 154,628
Charge for the period/ year 3,010 18 3,028 2,323 17 2,340 5,293 35 5,328
Disposals/write offs (3,550) (18) (3,568) - (29) (29) - (25) (25)
At 30 June/ 31 December 158,757 634 159,391 156,327 612 156,939 159,297 634 159,931
Net book value at 30 June/31 December 66,410 992 67,402 71,036 1,093 72,129 69,582 1,075 70,657
Impairment of Oil and Gas Assets
Period ended 30 June 2025
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 identification of
impairment indicators, mainly due to reduction in oil prices, adverse foreign
exchange rate movements and unfavourable changes in the Energy Profits Levy
regime in the period. An impairment indicator was noted for the Scotland CGU
given the delay in 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): $65/bbl for the
years 2025-2029 and $75/bbl thereafter
• USD/GBP foreign exchange rate:
Range of $1.36:£1.00 - $1.30:£1.00
• Post-tax discount rate: 8.5%
Outcome of impairment reviews:
The 30 June 2025 impairment assessment resulted in a recoverable amount
greater than the carrying amount by £0.03 million in the South CGU
(recoverable amount of £25.7 million) and £1.2 million in the North CGU
(recoverable amount of £29.9 million). At the Scotland CGU, no impairment
charge was recognised, with the recoverable amount of £0.3 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 30 June 2025 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 (6.83) (6.95) (2.46) (1.95)
South (4.69) (6.75) (2.66) (1.96)
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.
11 Financial Instruments - fair value disclosure
The Group uses the following hierarchy for determining and disclosing the fair
value of financial instruments by valuation technique:
● Level 1: quoted (unadjusted) prices in active markets for
identical assets or liabilities;
● Level 2: other valuation techniques for which all inputs which
have a significant effect on the recorded fair value are observable, either
directly or indirectly; and
● Level 3: valuation techniques which use inputs which have a
significant effect on the recorded fair value that are not based on observable
market data.
There are no non-recurring fair value measurements nor have there been any
transfers between levels of the fair value hierarchy.
Financial assets and liabilities measured at fair value
Level Unaudited Unaudited Audited
at 30 June at 30 June at 31 December 2024
2025 2024 £'000
£'000 £'000
Financial assets:
Derivative financial instruments 2 1,197 - 398
9
At 30 June/31 December 1,197 - 398
Level Unaudited Unaudited Audited
at 30 June at 30 June at 31 December 2024
2025 2024 £'000
£'000 £'000
Financial liabilities:
Derivative financial instruments 2 - (74) -
Contingent consideration (note 12) 3 - (480) (480)
At 30 June/31 December - (554) (480)
Fair value of derivative financial instruments
Commodity price hedges
The fair values of the commodity price hedges were provided by counterparties
with whom the trades have been entered into. These consist of Asian style put
and call options and swaps to sell oil. The hedges are valued by comparing
the fixed prices of the trades with prevailing market forward prices (or end
of day prices) and the difference multiplied by the traded volumes. These
results are discounted to provide a fair value.
Foreign exchange contracts
The fair value of foreign exchange contracts was provided by counterparties
with whom the trades have been entered into and is based on the difference
between the contracted forward rate and the forward rate at the balance sheet
date multiplied by the amount of foreign currency hedged, which is then
discounted to provide the fair value.
Fair value of other financial assets and financial liabilities
The fair values of all other financial assets and financial liabilities are
considered to be materially equivalent to their carrying values.
12 Provisions
Unaudited Unaudited Audited
at 30 June 2025 at 30 June 2024 at 31 December 2024
£'000 £'000 £'000
Decommis-sioning provisions Contingent consideration Total Decommis- sioning provisions Contingent consideration Total Decommis- sioning provisions Contingent consideration Total
At 1 January (60,890) (480) (61,370) (62,411) (2,731) (65,142) (62,411) (2,731) (65,142)
Utilisation of provision 347 - 347 656 - 656 1,147 - 1,147
Unwinding of discount (1,309) - (1,309) (1,221) - (1,221) (2,537) - (2,537)
Foreign exchange adjustments (13) - (13) - - - 10 - 10
Reassessment of decommissioning provision 310 - 310 970 - 970 2,901 - 2,901
Change in fair value of contingent consideration - 480 480 - 2,251 2,251 - 2,251 2,251
At 30 June/31 December (61,555) - (61,555) (62,006) (480) (62,486) (60,890) (480) (61,370)
Unaudited Unaudited Audited
at 30 June 2025 at 30 June 2024 at 31 December 2024
£'000 £'000 £'000
Decommis-sioning provisions Contingent consideration Total Decommis- sioning provisions Contingent consideration Total Decommis- sioning provisions Contingent consideration Total
Current (826) - (826) (1,858) - (1,858) (855) (480) (1,335)
Non-current (60,729) - (60,729) (60,148) (480) (60,628) (60,035) - (60,035)
At 30 June/ 31 December (61,555) - (61,555) (62,006) (480) (62,486) (60,890) (480) (61,370)
Decommissioning provision
The Group spent £0.3 million on decommissioning activities during the period
(six months ended 30 June 2024: £0.7 million; year ended 31 December 2024:
£1.1 million).
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 30 years from period end (30 June 2024: 1
to 29 years; 31 December 2024: 1 to 31 years). The provisions are based on the
Group's internal estimate as at 30 June 2025. 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 2026-2029 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 in the range of 2.5%
- 3% in the near term for the period 2025 - 2026 and incorporates the
long-term UK target inflation rate of 2% for the years 2027 and beyond.
A risk free rate range of 3.0% to 6.7% is used in the calculation of the
provision as at 30 June 2025 (30 June 2024: Risk free rate range of 3.0% to
5.8%, 31 December 2024: Risk free rate range of 3.0% to 6.3%).
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 £4.4 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 £6.4
million.
Contingent consideration
The carrying value of contingent consideration at the beginning of the period
related to the acquisition of GT Energy UK Limited (GT Energy), which was
payable in shares and was dependent on the timing of a business development
milestone being achieved. At the balance sheet date, management has assessed
that it is highly unlikely that the milestone will be met within the timelines
specified in the GT Energy share purchase agreement and, as a result, the
provision for contingent consideration has been released in full in the period
ended 30 June 2025.
13 Cash and cash equivalents and other financial assets
Unaudited Unaudited Audited
at 30 June at 30 June at 31 December
2025 2024 2024
£000 £000 £000
Cash and cash equivalents 4,277 4,199 4,708
Borrowings - including capitalised fees (6,490) (5,483) (11,734)
Net debt (2,213) (1,284) (7,026)
Capitalised fees (458) (577) (503)
Net debt excluding capitalised fees at 30 June/31 December (2,671) (1,861) (7,529)
Net debt reconciliation
Cash and cash Borrowings Total
equivalents
£000 £000 £000
At 1 January 2024 (audited) 3,855 (5,358) (1,503)
Interest paid on borrowings (154) - (154)
Repayment of RBL (5,541) 5,541 -
Drawdown on loan facility 6,110 (6,110) -
Foreign exchange adjustments 26 (4) 22
Capitalised transaction costs (626) 626 -
Other cash flows 529 - 529
Other non-cash movements - (178) (178)
At 30 June 2024 (unaudited) 4,199 (5,483) (1,284)
Interest paid on borrowings (325) - (325)
Other interest paid (14) - (14)
Drawdown on loan facility 6,420 (6,420) -
Foreign exchange adjustments (85) 233 148
Capitalised transaction costs 16 (16) -
Cash backing of performance guarantees (4,282) - (4,282)
Other cash flows (1,221) - (1,221)
Other non-cash movements - (48) (48)
At 31 December 2024 (audited) 4,708 (11,734) (7,026)
Interest paid on borrowings (694) - (694)
Repayment of loan facility (5,631) 5,631 -
Foreign exchange adjustments (636) (322) (958)
Other cash flows 6,530 - 6,530
Other non-cash movements - (65) (65)
At 30 June 2025 (unaudited) 4,277 (6,490) (2,213)
Borrowings
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.
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, carried a fixed interest rate of 9.4%
and was fully repaid on its contractual maturity date of 30 June 2025, and a
facility B which primarily provides funding for the Group's geothermal
development activities, carries an interest rate of Euribor + 6% and has a
five-year term with repayments commencing on 30 June 2026.
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.
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.
14 Share capital
Ordinary shares Deferred shares Share capital Share premium
No. Nominal value No. Nominal value Nominal value
£000 £000 £000 Value
£000
Issued and fully paid
At 1 January 2024 (audited) 128,347,033 3 303,305,534 30,331 30,334 103,189
SIP share issue- partnership 143,461 - - - - 13
SIP share issue - matching 171,567 - - - - 16
Shares issued in respect of MRP exercises 585,184 - - - - -
Shares issued in respect of EIP exercises 59,261 - - - - -
At 30 June 2024 (unaudited) 129,306,506 3 303,305,534 30,331 30,334 103,218
SIP share issue - partnership 193,267 - - - - 15
SIP share issue - matching 208,389 - - - - 15
Shares issued in respect of MRP exercises 482,649 - - - - -
Shares issued in respect of EIP exercises 5,997 - - - - -
At 31 December 2024 (audited) 130,196,808 3 303,305,534 30,331 30,334 103,248
SIP share issue - partnership 194,501 - - - - 14
SIP share issue - matching 228,768 - - - - 16
Shares issued in respect of MRP exercises - - - - - -
Shares issued in respect of EIP exercises - - - - - -
At 30 June 2025 (unaudited) 130,620,077 3 303,305,534 30,331 30,334 103,278
15 Acquisition of non-controlling interest
On 3 January 2025, the Group acquired a further 20% interest in the issued
share capital of its subsidiary 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.
Unaudited
6 months ended 30 June
2025
£000
Carrying amount of non-controlling interest acquired (428)
Consideration paid -
Decrease in equity attributable to owners of the Company 428
Decrease in equity attributable to owners of the Company comprised of a
decrease in retained earnings of £431 thousand and an increase in foreign
currency translation reserve of £3 thousand.
16 Operating Segments
An operating segment is a component of the Group that engages in a business
activity from which it may earn revenues and incur expenses, including
revenues and expenses that relate to transactions with any of the Group's
other components. All operating segments operating results are reviewed
regularly to make decisions about resources to be allocated to the Segment and
to assess its performance by the Chief Operating Decision Maker, which for the
Group is the Board of Directors. Segment results include items directly
attributable to a segment as well as those that can be allocated on a
reasonable basis. Unallocated items comprise mainly corporate assets and head
office expenses.
Unaudited at 30 June 2025
Oil and gas segment Geothermal segment Unallocated Total
£'000 £'000 £'000 £'000
External revenues 18,297 - - 18,297
Cost of sales (14,378) - - (14,378)
Gross profit 3,919 - - 3,919
Administrative expenses (1,643) (654) (246) (2,543)
Research and non-capitalised development costs - (303) - (303)
Exploration and evaluation assets impaired (26) - - (26)
Gain on derivative financial instruments 1,333 - - 1,333
Other income 4,540 - - 4,540
Segment operating profit/(loss) 8,123 (957) (246) 6,920
Finance costs (3,040)
Change in fair value of contingent consideration 480
Profit before income tax 4,360
Total assets at 30 June 112,866 8,246 - 121,112
Total liabilities at 30 June (74,966) (7,482) (166) (82,614)
Unaudited at 30 June 2024 Audited at 31 December 2024
Oil and gas segment Geothermal segment Unallo-cated Total Oil and gas segment Geothermal segment Unallo-cated Total
£'000 £'000 £'000 £'000 £'000 £'000 £'000 £'000
External revenues 23,230 - - 23,230 43,593 58 - 43,651
Cost of sales (13,257) - - (13,257) (28,717) (73) - (28,790)
Gross profit/(loss) 9,973 - - 9,973 14,876 (15) - 14,861
Administrative expenses (3,108) (616) (351) (4,075) (3,825) (2,050) (1,547) (7,422)
Research and non-capitalised development costs - (1,799) - (1,799) - (1,973) - (1,973)
Exploration and evaluation assets impaired (1,849) - - (1,849) (1,854) - - (1,854)
Impairment of development costs - (4,259) - (4,259) - (4,259) - (4,259)
(Loss)/profit on derivative financial instruments (74) - - (74) 737 - - 737
Other expense (2,000) (2,000) (2,000) (2,000)
Other income 3 - - 3 3 - - 3
Segment operating profit/(loss) 2,945 (6,674) (351) (4,080) 7,937 (8,297) (1,547) (1,907)
Finance costs (2,396) (4,805)
Change in fair value of contingent consideration* 2,251 2,251
Loss before income tax (4,225) (4,461)
Total assets at 30 June/31 December 2024 135,347 4,433 - 139,780 124,951 9,015 - 133,966
Total liabilities at 30 June/31 December 2024 (84,320) (2,261) (630) (87,211) (83,044) (7,891) (388) (91,323)
* See note 17 for explanation of reclassification of this balance.
The Group has two geographical areas of operation being the UK and Croatia.
All Group revenues are derived in the UK. There is a total of £8.1 million
(30 June 2024: £3.8; 31 December 2024: £7.5 million) of non-current assets
relating to operations in Croatia, with the remainder of the Group's
non-current assets relating to operations in the UK.
17 Reclassification
Change in fair value of contingent consideration of £2.3 million for the
period ended 30 June 2024 has been reclassified and presented after operating
profit/(loss) to align with the presentation treatment adopted in the audited
consolidated financial statements of the Group for the year ended 31 December
2024. This has resulted in operating loss of the Group for the period ended 30
June 2024 increasing by a corresponding amount with no impact on profit/(loss)
before tax.
Glossary
£ The lawful currency of the United Kingdom
$/USD The lawful currency of the United States of America
€ The lawful currency of the European Union
1P Low estimate of commercially recoverable reserves
2P Best estimate of commercially recoverable reserves
3P High estimate of commercially recoverable reserves
1C Low estimate or low case of Contingent Recoverable Resource quantity
2C Best estimate or mid case of Contingent Recoverable Resource quantity
3C High estimate or high case of Contingent Recoverable Resource quantity
AIM AIM market of the London Stock Exchange
Bbl(s)/d Barrel(s) of oil per day
Bcf billions of standard cubic feet of gas
boepd Barrels of oil equivalent per day
bopd Barrels of oil per day
Contingent Recoverable Resource - Contingent Recoverable Resource estimates
are prepared in accordance with the Petroleum Resources Management System
(PRMS), an industry recognised standard. A Contingent Recoverable Resource is
defined as discovered potentially recoverable quantities of hydrocarbons where
there is no current certainty that it will be commercially viable to produce
any portion of the contingent resources evaluated. Contingent Recoverable
Resources are further divided into three status groups: marginal,
sub‑marginal, and undetermined. Star Energy Group plc's Contingent
Recoverable Resources all fall into the undetermined group. Undetermined is
the status group where it is considered premature to clearly define the
ultimate chance of commerciality.
GIIP Gas initially in place
m Million
Mbbl Thousands of barrels
MMboe Millions of barrels of oil equivalent
MMscfd Millions of standard cubic feet per day
PEDL United Kingdom petroleum exploration and development licence
PL Production licence
Tcf Trillions of standard cubic feet of gas
UK United Kingdom
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