REG - Star Energy Group - Final Results
24/04/2024 07:00
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RNS Number : 7907L Star Energy Group PLC 24 April 2024
24 April 2024
Star Energy Group plc (AIM: STAR)
("Star Energy" or "the Company" or "the Group")
Full year results for the year ended 31 December 2023
Commenting today, Chris Hopkinson, Chief Executive Officer, said:
"We delivered strong production in 2023, capitalising on the improvement drive
we started at the end of 2022.
We were delighted, earlier this month, to secure a new €25 million secured
financing facility. Our ability to drawdown on this facility for our
geothermal activities will allow the business to be better positioned for the
longer term and should enable sustained growth. It will also give us greater
flexibility to continue to optimise the value of our entire asset portfolio,
investing in short cycle developments which will deliver additional production
and cash flow in the current higher commodity price environment."
Financial Performance
2023 2022
Revenues £49.5m £59.2m
Net debt* £1.6m £6.1m
Adjusted EBITDA* £16.1m £21.1m
Operating cash flow before working capital movements £15.0m £19.4m
Loss after tax £(5.5)m £(11.8)m
Cash and cash equivalents £3.9m £3.1m
Underlying operating profit* £9.1m £16.1m
* 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 bespoke €25 million transition financing
facility provided by Kommunalkredit Austria AG
o Retires BMO RBL and will support transition strategy into geothermal
energy and enables continued investment in the oil and gas business by
utilising existing cash flows
· Significant growth of geothermal portfolio
o Entry to new geography with Croatian acquisition and subsequent Sječe and
Pčelić licence awards
o Croatia provides a desirable combination of favourable geology for
geothermal energy as well as a supportive government and regulatory
environment
· We anticipate cash capex of £5.5 million in 2024 which includes
near-term incremental projects with short cycle returns, maintenance and
optimisation of existing oil and gas sites as well as maturing our development
projects portfolio; and expenditure on non-core asset rationalisation will
facilitate the future sale of a land holding
Operational Highlights
· Net production, beat guidance averaging 2,100 boepd in 2023 (2022:
1,898), with uptime across the portfolio remaining strong over the year
o Continued to optimise oil production from our existing wells through
selective investment in short cycle developments which deliver quick payback
· We anticipate net production of c.2,000 boepd and operating costs of
c.$41/boe (assuming an average exchange rate of £1:$1.26) in 2024
· DeGolyer & MacNaughton updated CPR values 2P NPV10 at $235
million (2022: $215 million) using an oil price assumption of c.$72/bbl for 5
years, then inflated at 2-3% p.a. from 2028 to 2050
· Development projects progressed to "shovel ready" position:
o Planning permission granted for Glentworth Phase 1 oil project,
environmental permits are expected imminently
o Corringham site preparation complete
o Bletchingley gas-to-wire secured grid connection
· NHS hospital trust geothermal projects in Manchester and Salisbury
progressing through feasibility stage
· Executed well test on Ernestinovo-3 well in Croatia, satisfying
exploration licence obligations. Data analysis from the well, once completed,
will allow a ranking exercise for all three licences and lead to the
production of a development plan for the most prospective opportunity
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)20
7993 9899
Chris Hopkinson, Chief Executive Officer
Ann-marie Wilkinson, Chief of Staff
Investec Bank plc (NOMAD and Joint Corporate Broker) Tel: +44 (0)20 7597 5970
Virginia Bull/Chris Sim/Charles Craven
Canaccord Genuity (Joint Corporate Broker) Tel: +44 (0)20 7523 8000
Henry Fitzgerald-O'Connor/James Asensio
Vigo Consulting Tel: +44 (0)20 7390 0230
Patrick d'Ancona/Finlay Thomson/Kendall Hill
Chairman's Statement
I am delighted to be presenting my first report as Chair of Star Energy Group
plc.
Whilst the Company delivered a strong operational performance in 2023, meeting
its production and health and safety targets for the year, underlying
operating profit was impacted primarily by lower oil prices.
Since the year end we have successfully concluded a refinancing of our
existing debt facility to give us the runway to deliver on our transition
strategy. Securing this facility is an important milestone for Star Energy.
It allows the Company to use cashflows from its existing oil and gas business
to optimise near-term conventional production (with quick pay-backs) whilst
also allowing it to lay the groundwork to deliver on its transition strategy;
developing and monetising the geothermal business in both the UK and Croatia
over time.
We believe that we have particular, tangible competitive advantages in making
the energy transition. We have a highly qualified team already in place and an
established track record in onshore development - everything from sub-surface
expertise and knowledge of planning and other environmental processes through
to long-term and responsible operatorship competence. These skills are
valuable in conventional and geothermal projects alike.
The restructuring and rebranding of the Company which we undertook last year,
were important steps in refocussing resource and redefining our strategic
direction. Our focus is on the responsible production of oil and gas onshore
in the UK and the development of geothermal opportunities that can benefit
from our significant expertise as an operator. The Company has a strong
technical capability and understanding of sub-surface considerations. We have
many years of working with local government and the communities we serve. We
have established relationships with the relevant regulatory, political and
environmental institutions. This trust is important as all concerned address
the new challenges of a more locally distributed energy future. We are
well-placed to support energy security, supply and affordability and we
already have a significant workforce based in local communities.
In geothermal, we have made good progress in the UK, having been awarded
contracts to develop geothermal heating projects with a particular focus on
working with the NHS, a major consumer of heat. Even before the invasion of
Ukraine, the EU had been interested to expand geothermal energy and this
interest has grown significantly. The acquisition of the Ernestinovo
geothermal project in North-eastern Croatia, as well as the award of the
Pčelić and Sječe geothermal exploration licences in October 2023, will
enable us to diversify into geothermal electricity generation in a supportive
jurisdiction and rapidly developing market.
The UK Energy Profits Levy (EPL) has a significant impact on post-tax
profitability for all UK oil and gas producers, such that the sector now has
the highest taxes for any UK industrial sector. The EPL is an unwelcome
obligation that we do not believe was ever designed to encumber the minor
onshore sector, and in particular, a company which has taken a strategic
decision to pivot from its fossil fuel roots to a renewable future as
cashflows permit over time. The Company however benefits from lower tax
rates than most of its peers given its c.£240 million tax losses.
Board Changes
In June 2023, Chris Hopkinson was appointed as Chief Executive Officer (CEO)
of the Company having been acting Interim Executive Chairman since September
2022. At the same time, I was appointed as Non-executive Chairman, having
been a Non-executive Director of the Company since 2017.
In October 2023, Doug Fleming informed the Board of his intention to step down
as a Non-executive Director, as he took up a new fulltime executive role. He
remained in his Non-executive role until 23 January 2024 and we thank him for
his contribution and commitment to the Group.
In December 2023, we welcomed two new Non-executive Directors to the Board,
Aneliya Erdly and Anthony White MBE, each bringing new perspectives relevant
to an industrial landscape undergoing significant change. Aneliya brings a
wealth of expertise in building from scratch and running renewable energy
generation businesses in the private sector, as well as in assisting with
their energy transition strategies. Tony has over thirty five years experience
in international power markets and the policy issues inherent in transitioning
to a low carbon economy. He has been involved in almost all aspects of the
sector from research through to strategy, finance, international development
and policy. This includes industrial roles and as a leading City energy
analyst. He has assisted governments in structural reform of the energy sector
and is a highly respected figure in the energy industry.
The membership of the Company's board committees are now as follows:
Audit Committee: Kate
Coppinger (Chair), Anthony White
Remuneration Committee: Philip Jackson (Chair), Kate
Coppinger, Aneliya Erdly
Nomination Committee: Philip Jackson (Chair),
Anthony White
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
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. The Company will accordingly
continue to optimise 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 are confident that the transformation towards geothermal provides a strong
foundation and a broad range of opportunities for the continued development of
the business and value creation for shareholders in time.
Operational Review
Well uptime remained strong across the year with net production for the period
averaging 2,100 boepd (2022: 1,898 boepd). Good results from workovers at
Singleton and a rolling programme of well optimisation and stimulation yielded
additional production, equal to c.50 boepd. Underlying cash operating costs
per boe were c.$40.3/boe (based on an average exchange rate of £1:$1.24) vs.
$41.5/boe in 2022.
We have stabilised and reset our production levels through the execution of
capital efficient incremental production opportunities, streamlining our
operations and driving quicker and better decision making within the
operational assets. Our operating costs per barrel have reduced despite
widespread cost inflation through both production uplift, but also targeted
investment on specific fields.
We continue to suffer from regulatory creep and ever-increasing delays in
obtaining regulatory approval for environmental permits. In 2023, waiting
times to have an application "duly made" and then addressed by an officer,
were commonly in excess of 12 months. The Environment Agency acknowledge
these significant delays, but do not seem able to adequately address the
issue. This has both cost and environmental consequences with real world
impacts such as having to collect, transport and then inject into subsurface
reservoirs uncontaminated rainwater from a variety of operational sites.
Simple and standard permits for the discharge of uncontaminated rainwater take
months to obtain.
During 2023, we fully abandoned three wells and partially abandoned a further
three. Despite cost inflation on specific materials, services and labour, we
have seen well on well cost reduction of c.10%.
We will continue to invest in capital efficient well optimisation
opportunities, in reducing site operating costs and in fully abandoning
non-producing and sub-economic fields and relinquishing licences.
Reserves and Resources Competent Persons Report (CPR)
In February 2024, the Company announced the publication of the full and final
results of the CPR by DeGolyer & MacNaughton, a leading independent
international reserves and resources auditor.
Net Reserves & Contingent Resources as at 31 Dec 2023 (MMboe).
1P 2P 2C
Reserves & Resources as at 31 Dec 2022 11.17 17.04 18.72
Production during the period (0.70) (0.70) -
Additions & revisions during the period 1.24 1.13 (0.13)
Reserves & Resources as at 31 Dec 2023 11.71 17.47 18.59
*Oil price assumption of c.$72/bbl for 5 years, then inflated at 2-3% p.a.
from 2028 to 2050
**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, Welton.
The report values our conventional assets at $235 million (2022: $215 million)
on a 2P NPV10 basis.
The full report can be found at
https://www.starenergygroupplc.com/investors/reports-publications-presentations/
Development
Oil and Gas
Glentworth
In April 2023, Lincolnshire County Council granted planning consent for the
Glentworth development. The development is for an initial appraisal well and
up to six horizontal development wells in Phase II.
Phase I has the potential to add c.200 bopd and development of c.1.0 MMstb 2P
reserves (currently 2P undeveloped). If Phase I is successful, this will be
followed by further development drilling in subsequent years with the
subsequent development having the potential to add an additional 500 bopd and
the addition of c.2MMstb 2P reserves from 2C. Phase I of the project has a
mid-case NPV of £17.5 million.
Environmental permit applications associated with the project were submitted
in October 2022. The issue of these permits, required before operations can
commence, is still awaited from the Environment Agency.
Corringham
The extensive site upgrades required to drill an additional well at Corringham
were completed in Q4 2023. Phase 1 of the Corringham project is now
"shovel ready" and will be assessed as part of a capital allocation exercise
following the refinancing in April 2024. The project can develop c.350 Mstb of
2P undeveloped reserves and initial production is expected to be c.110 bopd.
The success of Phase 1 of the project unlocks Phase 2 which could develop
c.935 Mstb of current 2C resources.
Bletchingley
The Bletchingley gas to wire project now has full planning consent,
environmental permits and a secured grid connection. Further work by the
Distribution Network Operator is underway to optimise the grid connection
routing. Subject to this being finalised, expected imminently, the project
is now "shovel ready".
Geothermal Energy
Star Energy is fast developing its geothermal portfolio, deploying our decades
of expertise in developing subsurface energy sources. Our geothermal
portfolio benefits directly from our geoscience, well engineering, drilling
and operational expertise.
UK
The UK Government is starting to wake up to the potential for the deployment
of geothermal, engaging directly with the industry through a research project
to assess the impact of different funding support schemes for geothermal. The
final report is likely to be published in September 2024.
There is a significant opportunity in the UK, in particular in decarbonising
energy sources throughout the public sector estate and in particular, the NHS.
The British Geological Survey in collaboration with sustainability
consultants, Arup, the North East Local Enterprise Partnership (NELEP) and
Durham Energy Institute have highlighted the need for a review of funding
support schemes for geothermal heating projects. Their findings, published
in a White Paper( 1 ) in June 2023, highlighted that the public sector estate
is one of the main emitters of greenhouse gases (for heating) in the UK. The
estate has large buildings (for example hospitals, prisons, army barracks)
with predictable and continuous heating requirements, ideal for geothermal
heating.
Developing geothermal projects for NHS hospitals with high heat demand that
overlie potential geothermal targets could save emissions of between 1.3-22.7
kt CO2 equivalent per year for individual hospital sites in England.
Developing geothermal projects for the 30 top-ranking hospital sites (based on
heat demand) could save emissions of 281 kt CO2 equivalent per year.
Star Energy is developing a market leading position in this area. In Q2
2023, as part of the five tenders submitted through the Carbon and Energy Fund
(CEF) Framework in late 2022, Star Energy was selected by Manchester
University NHS Foundation Trust to deliver a geothermal heat solution for the
Wythenshawe Hospital and by Salisbury NHS Foundation Trust to deliver a
geothermal plant to fulfil the full heat requirements of the hospital.
We were also awarded Royal Preston Hospital however, the project is reliant on
a Government decision regarding funding for a new hospital in order to proceed
further.
At Salisbury, we are well underway with the initial feasibility work including
seismic reprocessing, strategic seismic acquisition and interpretation and
pre-planning and permitting. At Wythenshawe, feasibility will commence in Q2
2024 with a seismic programme.
The Stoke project continues to suffer delays. An application, in partnership
with Scottish and Southern Energy (SSE), for grant funding was made to the
Green Heat Network Fund in November 2022. The grant is to support the
deployment of a city-wide district heating network, fed by a deep geothermal
heat source. Since the application, SSE have been refining their commercial
model and engaging in further discussions with both the council and other end
users in Stoke. As well as this, SSE engaged Baker Hughes to carry out
project due diligence. This due diligence was conducted during the year and
the technical and commercial aspects of the geothermal heat provision within
the project were signed off by the consultant towards the end of Q3 2023.
Croatia
In August 2023, we announced our first overseas geothermal investment through
the acquisition of a 51% interest in A14 Energy that owns, through its
subsidiary, IGeoPen d.o.o., the Ernestinovo exploration licence in the highly
prospective Pannonian Basin in northern Croatia.
The vast Croatian geothermal resource is well understood, with extensive data
available from over 4,000 exploration and appraisal wells drilled during a
period of hydrocarbon exploration in Croatia.
The geological characteristics are well suited for electricity generation with
a geothermal gradient proven to be 60% higher than the European average and
electricity can be sold bi-laterally throughout the EU.
In October 2023, our partnership was awarded two further, highly prospective
geothermal licences by the Croatian Hydrocarbon Agency.
The two licences, each with an initial five year exploration term, Sječe and
Pčelić, are located in the Drava depression geological region (the
southwestern area of the Pannonian basin), the same region as the Ernestinovo
licence is located. The licence commitments are to drill four and three wells
respectively.
The Ernestinovo licence itself, covers 76.7km(2) and has data from three deep
exploration wells drilled nearby in the 1990s. Work began on the construction
of a new well pad and securing necessary permits and the Ernestinovo-3 well
was successfully re-entered and prepared for testing in December 2023/early
January 2024. Since financial year end, we have successfully completed all
the well tests on the Ernestinovo-3 well necessary to convert the licence to a
25 year exploitation licence and have submitted the required data package to
the Hydrocarbon Ministry. We expect the Ministry to respond sometime in H2.
The primary objective of the testing programme was to secure the licence and
obtain additional technical data on permeability and chemistry. Combining
this additional data with the existing technical data from all three secured
licences, the Company will rank the opportunities with a view to progressing
commercial development of the sites in an optimal manner.
Financial Review
The Group continued to progress its strategy during 2023, continuing to
optimise production from its oil and gas assets whilst positioning for longer
term growth in the geothermal business segment. Strong performance in the oil
and gas business was driven by increased production for the year, which
averaged 2,100 boepd (2022: 1,898 boepd), ahead of our production guidance for
the year. The higher production reflects the positive results from workovers
and other well optimisation and stimulation activities carried out during the
year. Higher operating cash flows from the increase in production volumes
was offset by lower commodity prices and a weaker US dollar compared to
2022. Brent oil prices declined from an average of $101/bbl in 2022 to
$83/bbl in 2023. Natural gas prices declined in the year from 262p/therm for
2022 to 102p/therm for 2023. Sterling strengthened slightly during the year
with average GBP/USD rates of £1:$1.25 in 2023 compared to £1:$1.23 in 2022,
negatively impacting our revenues which are mainly denominated in USD.
Revenue for the year was £49.5 million compared to £59.2 million in 2022, a
reduction of £9.7 million. The decrease compared to 2022 mainly arose as a
result of a reduction in oil revenues (excluding third party oil sales) of
£4.5 million due to lower prices and a reduction in gas and electricity
revenues of £2.3 million and £1.5 million respectively, due to both lower
volumes and prices. In addition, revenues from the sale of third party oil
reduced by £1.5 million due to lower volumes processed by the Group. The
Group incurred a net oil price hedging loss of £0.03 million for the year
compared to a loss of £6.0 million in 2022. Other cost of sales increased
marginally to £24.1 million (2022: £24.0 million). Additional costs from
higher production and inflationary increases were partially offset by the
reduction in costs due to processing fewer third-party volumes. Underlying
operating costs (which exclude third party oil but include costs relating to
leases capitalised under IFRS 16) were £32.4 ($40.3) per boe for the year
(2022: £33.4 ($41.5) per boe) reflecting our ongoing focus on increasing
production and improving efficiency.
Realised Price Per Barrel
2023 2022
$ $
Realised price per barrel 79.9 82.7
Administrative expenses per BOE 12.0 11.5
Other operating costs (underlying) 30.0 30.8
Well services 7.2 8.0
Transportation and storage 3.1 2.7
Adjusted EBITDA was £16.1 million (2022: £21.1 million) and the underlying
operating profit was £9.1 million (2022: £16.1 million), with the variance
resulting primarily from a reduction in revenues, net of hedges and higher
administrative costs.
Adjusted EBITDA
Reconciliation of profit/(loss) before tax to Adjusted EBITDA
2023 2022
£m £m
Profit/(loss) before tax 2.8 (18.4)
Net finance costs 4.4 5.1
Depletion, depreciation & amortisation** 8.3 6.3
Oil and gas assets net impairment (reversal)/charge - -(*)
Exploration and evaluation assets written off 0.5 30.0
Goodwill impairment 0.1 -
EBITDA 16.1 23.0
Lease rentals capitalised under IFRS 16 (1.8) (1.7)
Share-based payment charge 0.7 1.0
Unrealised loss/(gain) on hedges 0.5 (1.9)
Redundancy costs (net of capitalisation) 0.1 0.7
Acquisition costs 0.5 -
Adjusted EBITDA 16.1 21.1
* Rounds to nil
** Includes depreciation charge recorded in administrative expenses
Underlying operating profit
Reconciliation of operating profit/(loss) to underlying operating profit
2023 2022
£m £m
Operating profit/(loss) 7.2 (13.3)
Lease rentals capitalised under IFRS 16 (1.8) (1.7)
Depreciation charge of right-of-use assets 1.3 1.3
Share-based payment charge 0.7 1.0
Oil and gas assets net impairment (reversal)/charge - -(*)
Exploration and evaluation assets written off 0.5 30.0
Goodwill impairment 0.1 -
Unrealised loss/(gain) on hedges 0.5 (1.9)
Redundancy costs (net of capitalisation) 0.1 0.7
Acquisition costs 0.5 -
Underlying operating profit 9.1 16.1
* Rounds to nil
Strong operating cash flows resulted in a continued reduction in the Group's
net debt which amounted to £1.6 million as at 31 December 2023 (31 December
2022: £6.1 million).
31 December 2023 31 December 2022
£m £m
Debt (nominal value excluding capitalised expenses) (5.5) (9.2)
Cash and cash equivalents 3.9 3.1
Net debt (1.6) (6.1)
Income Statement
The Group recognised revenues of £49.5 million for the year (2022: £59.2
million). Oil revenue for the year amounted to £44.8 million compared to
£49.3 million in 2022 representing a reduction of £4.5 million. The average
pre-hedge realised price for the year was $79.0/bbl (2022: $98.6/bbl) and
post-hedge was $79.9/bbl (2022: $82.7/bbl). In addition, a strengthening of UK
pound sterling against USD from an average of £1: $1.23 in 2022 to £1: $1.25
in 2023 also contributed to the reduction in oil revenue. The impact of the
above was partially offset by an increase in the Group's oil production
volumes which averaged 2,100 boepd in the current year as compared to 1,898
boepd in 2022.
Gas and electricity revenue for 2023 amounted to £1.9 million and £1.2
million respectively as compared to £4.2 million and £2.7 million
respectively in 2022 with the reduction in revenue attributable to a
combination of reduced prices and lower sale volumes.
Revenues also included £1.2 million (2022: £2.7 million) relating to the
sale of third party oil, and have reduced due to lower volumes processed in
the year.
A loss of £0.03 million was recognised on oil hedges during the year (2022:
loss of £6.0 million).
Cost of sales for the year were £32.3 million (2022: £30.3 million)
including DD&A of £8.2 million (2022: £6.3 million), and other costs of
sales of £24.1 million (2022: £24.0 million). The DD&A charge has
increased by £1.9 million in the year mainly due to an increase in the
production volumes in the year. In addition, the Group has written off the net
book value of field assets in respect of certain non-producing fields with no
remaining proven and probable reserves as at 1 January 2023 as well as certain
costs on a rationalisation project at our Holybourne site. Other costs of
sales increased by £0.1 million compared to 2022 mainly due to £1.2 million
arising from the higher well services and maintenance equipment cost to boost
production, higher transport costs and other inflationary impacts and an
increase in cost of £0.4 million due to stock movements. The increase was
partially offset by a reduction of £1.4 million due to lower third party
volumes being processed in the year.
Adjusted EBITDA in the year was £16.1 million (2022: £21.1 million). The
gross profit for the year was £17.1 million (2022: £28.8 million).
Administrative costs increased by £1.1 million to £7.3 million (2022: £6.2
million) primarily due to increases in legal and professional fees due to the
acquisition of the Croatian geothermal business in the year and services
procured in relation to the refinancing of the Group's borrowings, together
with general inflationary increases.
Research and non-capitalised development costs were £2.0 million (2022: £0.1
million), of which £1.6 million related to our operations in Croatia
primarily in respect of well re-entry activity to test the geothermal
potential of 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 amounts
incurred on the NHS trust geothermal projects, net of any grants received.
Exploration and evaluation costs written off during the year were £0.5
million including costs relating to our oil and gas assets where there is no
further development prospect and trailing costs on previously impaired
unconventional licences. In the previous year we had written off exploration
and evaluation costs of £30.0 million of previously capitalised shale
exploration costs.
Goodwill of £0.1 million related to the Leščan licence was written off in
the year once it was determined that the Group had not been successful in its
bid for this licence (see note 6).
No impairment or impairment reversal has been recognised in relation to the
Group's oil and gas assets in the year (see note 7). In the prior year a net
impairment reversal of £0.03 million was recorded on oil and gas assets.
Net finance costs were £4.4 million (2022: £5.1 million). Interest and
amortisation of finance fees on borrowings were £1.2 million (2022: £1.2
million) with the impact of a reduction in the amount drawn being offset by
higher interest rates. Finance costs also included the unwinding of the
discount on provisions of £2.6 million (2022: £1.7 million) and interest on
leases of £0.7 million (2022: £0.7 million). Net foreign exchange gains
during the year were £0.2 million (2022: loss of £1.4 million) mainly on our
USD based RBL borrowings.
A net tax charge of £8.3 million (2022: net tax credit of £6.6 million) was
recognised during the year, mainly due to the reduction in the deferred tax
asset relating to tax losses reflecting the lower forecast oil prices (£6.8
million) and a current tax charge arising as a result of the Energy Profits
Levy (£1.1 million).
Cash Flow
Net cash generated from operating activities for the year was £17.2 million
(2022: £18.1 million). The reduction was primarily due to the decrease in
cash inflows from revenue generated from customers of £7.4 million and an
increase in the cash outflows from operating costs, administrative expenses
and research and non-capitalised development costs of £2.4 million, partially
offset by an increase in cash inflows from realised derivatives of £8.5
million and a reduction in abandonment spend of £0.4 million.
The Group invested £8.5 million across its asset base during the year (2022:
£7.9 million). This included £7.6 million of investment in our oil and gas
assets primarily for site preparation and purchase of long lead items required
for a development project at Corringham, rationalisation works at the
Holybourne site and a number of projects to increase production from existing
wells and to offset field declines by upgrading existing facilities and
systems. We invested £0.3 million on oil exploration opportunities at
existing fields. £0.6 million was spent to progress the Stoke-on-Trent
geothermal project.
The Group spent £1.3 million on the acquisition of a 51% equity interest in
A14 Energy Limited, the parent company of IGeoPen d.o.o za trogovinu i usluge
which owned a geothermal business in Croatia, including the Ernestinovo
licence. The Group generated £0.2 million from the sale of non-core land.
We repaid £3.3 million ($4.0 million) (2022: £8.0 million ($10 million)) of
the outstanding RBL loan and paid £0.8 million ($1.0 million) in loan
interest (2022: £1.0 million ($1.2 million )). In addition, the Group paid
interest charges of £0.6 million (2022: £ nil) in respect of performance
guarantees for our Croatian geothermal licences.
Realised gains on oil hedges were £0.5 million (2022: realised loss of £8.0
million)
Cash and cash equivalents were £3.9 million at the end of the year (2022:
£3.1 million).
Balance Sheet
Net assets reduced by £3.4 million to £54.9 million at 31 December 2023
(2022: £58.3 million), primarily due to a reduction in the deferred tax asset
and an increase in trade and other payables and corporation tax payable,
partially offset by an increase in intangible assets following the acquisition
of 51% equity interest in A14 Energy Limited, and a reduction in borrowings.
Property, plant and equipment reduced by £0.7 million during the year as the
capital expenditure incurred of £6.9 million was more than offset by the
DD&A charge of £7.0 million, disposals of fixed assets of £0.3 million
and a reduction in the value of decommissioning assets of £0.3 million.
Intangible assets increased by £4.5 million mainly due to the capitalisation
of the cost of the Ernestinovo licence (£2.5 million) and goodwill (£1.3
million) related to the acquisition of the 51% equity interest in A14 Energy
Limited. In addition, £0.7 million was capitalised in relation to the
Stoke-on-Trent project and £0.6 million in relation to exploration and
evaluation activities on our oil and gas licences. The Group wrote off
exploration costs and goodwill in the year of £0.5 million and £0.1 million
respectively.
The provision for decommissioning costs decreased by £0.4 million (2022:
£3.2 million) as a result of abandonment activity during the year (£2.9
million), a change in the assumptions used in the provision for the
calculation of discount rates, expected costs and timing of abandonments
(£0.1 million), offset by the unwinding of the discount on the provision
(£2.6 million).
Trade and other payables increased by £2.3 million as a result of timing of
activity on capital and abandonment projects, higher operating and
administrative expenses and a liability recognised of £0.9 million related to
the award of the Sječe and Pčelić Croatian geothermal exploration licences.
The deferred tax asset reduced by £7.6 million from £44.8 million at 31
December 2022 to £37.2 million at 31 December 2023 mainly due to a change in
forecast utilisation of available tax losses.
The Group recognised a current tax liability of £1.1 million at 31 December
2023 for the Energy Profits Levy (2022: £nil).
At 31 December 2023, right-of-use assets were £7.4 million (2022: £7.4
million) and related lease liabilities were £7.8 million (2022: £7.8
million).
We repaid £3.3 million ($4.0 million) (2022: £8.0 million ($10.0 million))
on our RBL loan facility during the year reducing net debt to £1.6 million by
year end (2022: £6.1 million).
2024 Capital Expenditure
Following the refinancing in April 2024, we are working on a full capital
expenditure plan for 2024. However, we are committing to £4.5 million on
near-term incremental projects with short cycle returns to take advantage of
current high commodity prices, maintenance and the optimisation of our
existing conventional sites as well as maturing our conventional development
projects portfolio. A further £1.0 million expenditure on non-core asset
rationalisation will facilitate the future sale of a land holding.
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 further reductions in commodity
prices, fluctuations of sterling and reductions in forecast oil and gas
production rates.
We have prepared our going concern assessment extending up to 30 September
2025.
Crude oil prices saw a decline in 2023 compared to 2022. The higher prices
prevailing during 2022 were primarily as a result of a spike following
Russia's invasion of Ukraine in February 2022 which led to disrupted Russian
supply and global concerns over energy security. Prices increased in H2 2023
but remained below those seen in 2022. More recently, geopolitical tensions,
including the prospect of a wider conflict in the Middle East and attacks on
Russian refineries have led to concerns over supply disruption which, together
with an extension of OPEC output cuts through to June 2024, have led to higher
prices in 2024.
The Group has generated strong operating cashflows in 2023, following the
successful production drive and reorganisation undertaken in Q4 2022, putting
the business on a resilient and sustainable footing, able to withstand a wider
range of commodity prices. 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. In respect
of the latter, the Group successfully completed a €25 million financing
facility with Kommunalkredit, Austria in March 2024, securing funds to repay
the outstanding balance on its RBL facility which was due to mature at the end
of June 2024, and providing funding for its energy transition strategy.
The Group's base case cash flow forecast was run with average oil prices of
$85/bbl for 2024, falling to $80/bbl for H1 2025 and $77/bbl for H2 2025, and
a foreign exchange rate of an average $1.26/£1 for 2024 and $1.27/£1 for
2025. In this base case scenario, our forecasts show that the Group will have
sufficient financial headroom to meet the applicable financial covenants over
the going concern assessment period.
Management has also prepared a downside case with average oil prices at
$85/bbl for H1 2024 and $81/bbl for H2 2024, falling to $76/bbl for H1 2025
and $73/bbl for H2 2025. We used an average exchange rate of $1.26/£1 for H1
2024, $1.29/£1 for H2 2024 and $1.30/£1 for 2025. Our downside case also
included an average reduction in production of 5% over the period. In the
event of a downside scenario, management would 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 over the going concern assessment period.
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.
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.
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 to be consistent with previous periods.
CONSOLIDATED INCOME STATEMENT
FOR THE YEAR ENDED 31 DECEMBER 2023
Note Year ended Year ended
31 December 31 December 2022
2023 £000
£000
Revenue 2 49,466 59,171
Cost of sales:
Depletion, depreciation and amortisation (8,241) (6,302)
Other costs of sales (24,135) (24,019)
(32,376) (30,321)
Gross profit 17,090 28,850
Administrative expenses (7,290) (6,215)
Research and non-capitalised development costs (2,002) (114)
Exploration and evaluation assets written-off 6 (456) (30,018)
Impairment of goodwill 6 (130) -
Oil and gas assets impairment 7 - (10,457)
Reversal of oil and gas assets impairment 7 - 10,489
Loss on derivative financial instruments (25) (6,027)
Other income 8 159
Operating profit/(loss) 7,195 (13,333)
Finance income 3 177 8
Finance costs 3 (4,603) (5,091)
Profit/(loss) before tax 2,769 (18,416)
Income tax (charge)/credit 4 (8,260) 6,638
Loss after tax (5,491) (11,778)
Attributable to:
Owners of the Parent Company (4,493) (11,778)
Non-controlling interest (998) -
(5,491) (11,778)
Loss per share attributable to equity shareholders:
Basic loss per share 5 (3.52p) (9.35p)
Diluted loss per share 5 (3.52p) (9.35p)
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE YEAR ENDED 31 DECEMBER 2023
Year ended Year ended
31 December 31 December
2023 2022
£000 £000
Loss for the year (5,491) (11,778)
Other comprehensive income for the year:
Items that may be reclassified subsequently to profit or loss:
Foreign exchange differences on translation of foreign operations 19 -
Total comprehensive loss for the year (5,472) (11,778)
Total comprehensive loss attributable to:
Owners of the Parent Company (4,477) (11,778)
Non-controlling interest (995) -
(5,472) (11,778)
CONSOLIDATED BALANCE SHEET
AS AT 31 DECEMBER 2023
Note 31 December 31 December
2023 2022
£000 £000
ASSETS
Non-current assets
Intangible assets 6 13,823 9,268
Property, plant and equipment 7 73,994 74,731
Right-of-use assets 7,426 7,383
Restricted cash 8 - 410
Deferred tax asset 4 37,192 44,813
132,435 136,605
Current assets
Inventories 1,522 1,667
Trade and other receivables 7,067 7,098
Cash and cash equivalents 8 3,855 3,092
Restricted cash 8 410 -
Derivative financial instruments - 525
12,854 12,382
Total assets 145,289 148,987
LIABILITIES
Current liabilities
Trade and other payables (10,971) (8,264)
Corporation tax payable 4 (1,099) -
Borrowings 9 (5,358) (3,325)
Lease liabilities (865) (738)
Provisions 10 (2,236) (6,840)
(20,529) (19,167)
Non-current liabilities
Borrowings 9 - (5,418)
Other payables - (369)
Lease liabilities (6,981) (7,042)
Provisions 10 (62,906) (58,716)
(69,887) (71,545)
Total liabilities (90,416) (90,712)
Net assets 54,873 58,275
CONSOLIDATED BALANCE SHEET (CONTINUED)
AS AT 31 DECEMBER 2023
Note 31 December 31 December
2023 2022
£000 £000
EQUITY
Capital and reserves
Called up share capital 30,334 30,334
Share premium account 103,189 103,068
Foreign currency translation reserve 3,815 3,799
Other reserves 38,324 37,617
Accumulated deficit (121,036) (116,543)
Equity attributable to owners of the Company 54,626 58,275
Non-controlling interest 247 -
Total equity 54,873 58,275
These financial statements were approved and authorised for issue by the Board
on 24 April 2024 and are signed on its behalf by:
Chris
Hopkinson
Frances Ward
Chief Executive
Officer
Chief Financial Officer
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEAR ENDED 31 DECEMBER 2023
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 (note 11) equity
£000 account translation £000 £000 £000
£000 reserve*
£000
At 1 January 2022 30,333 102,992 3,799 36,257 (104,765) 68,616 - 68,616
Loss for the year - - - - (11,778) (11,778) - (11,778)
Share options issued under the employee share plan - - - 1,360 - 1,360 - 1,360
Issue of shares 1 76 - - - 77 - 77
At 31 December 2022 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 (note 11) - - - - - - 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
* The foreign currency translation reserve includes an amount of
£3,799 thousand (2022: £3,799 thousand) in respect of 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 2023
Note Year ended Year ended
31 December 2023 31 December 2022
£000 £000
Cash flows from operating activities:
Profit/(loss) before tax 2,769 (18,416)
Depletion, depreciation and amortisation 8,291 6,338
Abandonment costs/other provisions utilised or released (2,186) (2,579)
Share-based payment charge 633 934
Exploration and evaluation assets written-off 6 456 30,018
Impairment of goodwill 6 130 -
Reversal of oil and gas assets impairment 7 - (10,489)
Oil and gas assets impairment 7 - 10,457
Unrealised loss/(gain) on oil price derivatives 525 (1,934)
Gain on sale of fixed assets (8) -
Finance income 3 (177) (8)
Finance costs 3 4,603 5,091
Operating cash flows before working capital movements 15,036 19,412
Decrease/(increase) in trade and other receivables and other financial assets 1,482 (1,607)
Increase in trade and other payables 553 919
Decrease/(increase) in inventories 145 (575)
Net cash generated from operating activities 17,216 18,149
Cash flows from investing activities:
Purchase of intangible exploration and evaluation assets (343) (516)
Purchase of property, plant and equipment (7,547) (7,196)
Purchase of intangible development assets (619) (202)
Acquisition of subsidiary, net of cash acquired 11 (1,282) -
Proceeds from disposal of property, plant and equipment 152 -
Interest received 3 24 8
Net cash used in investing activities (9,615) (7,906)
Cash flows from financing activities:
Cash proceeds from issue of ordinary share capital 42 44
Repayment of Reserves Based Lending facility 8 (3,284) (7,985)
Repayment of principal portion of lease liabilities (1,255) (1,059)
Repayment of interest on lease liabilities (727) (707)
Interest paid 8 (1,384) (950)
Net cash used in financing activities (6,608) (10,657)
Net increase/(decrease) in cash and cash equivalents in the year 993 (414)
Net foreign exchange differences 8 (230) 217
Cash and cash equivalents at the beginning of the year 3,092 3,289
Cash and cash equivalents at the end of the year 8 3,855 3,092
CONSOLIDATED FINANCIAL STATEMENTS - NOTES
FOR THE YEAR ENDED 31 DECEMBER 2023
1 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 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 2024.
The financial information for the year ended 31 December 2023 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 2022 have been delivered to the Registrar of Companies and
those for 2023 will be delivered following the Company's annual general
meeting. The auditor has reported on the 2023 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
2022. There have been a number of amendments to accounting standards and new
interpretations issued by the International Accounting Standards Board which
were applicable from 1 January 2023. These did not have a material impact on
the accounting policies, methods of computation or presentation applied by the
Group.
There are also a number of amendments to accounting standards and new
interpretations issued by the International Accounting Standards Board which
will be applicable from 1 January 2024 onwards. 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 newly issued
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 2023 Annual Report and Financial
Statements.
Star Energy Group plc (formerly known as IGas Energy 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 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 further reductions in commodity
prices, fluctuations of sterling and reductions in forecast oil and gas
production rates.
We have prepared our going concern assessment extending up to 30 September
2025.
Crude oil prices saw a decline in 2023 compared to 2022. The higher prices
prevailing during 2022 were primarily as a result of a spike following
Russia's invasion of Ukraine in February 2022 which led to disrupted Russian
supply and global concerns over energy security. Prices increased in H2 2023
but remained below those seen in 2022. More recently, geopolitical tensions,
including the prospect of a wider conflict in the Middle East and attacks on
Russian refineries have led to concerns over supply disruption which, together
with an extension of OPEC output cuts through to June 2024, have led to higher
prices in 2024.
The Group has generated strong operating cashflows in 2023, following the
successful production drive and reorganisation undertaken in Q4 2022, putting
the business on a resilient and sustainable footing, able to withstand a wider
range of commodity prices. 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. In respect
of the latter, the Group successfully completed a €25 million financing
facility with Kommunalkredit, Austria in March 2024, securing funds to repay
the outstanding balance on its RBL facility which was due to mature at the end
of June 2024, and providing funding for its energy transition strategy.
The Group's base case cash flow forecast was run with average oil prices of
$85/bbl for 2024, falling to $80/bbl for H1 2025 and $77/bbl for H2 2025, and
a foreign exchange rate of an average $1.26/£1 for 2024 and $1.27/£1 for
2025. In this base case scenario, our forecasts show that the Group will have
sufficient financial headroom to meet the applicable financial covenants over
the going concern assessment period.
Management has also prepared a downside case with average oil prices at
$85/bbl for H1 2024 and $81/bbl for H2 2024, falling to $76/bbl for H1 2025
and $73/bbl for H2 2025. We used an average exchange rate of $1.26/£1 for H1
2024, $1.29/£1 for H2 2024 and $1.30/£1 for 2025. Our downside case also
included an average reduction in production of 5% over the period. In the
event of a downside scenario, management would 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 over the going concern assessment period.
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
2023 2022
£000 £000
Oil sales 46,448 52,409
Electricity sales 1,162 2,645
Gas sales 1,856 4,117
49,466 59,171
Revenues of approximately £23.6 million and £22.8 million were derived from
the Group's two largest customers (2022: £26.4 million and £26.0 million)
and are attributed to the oil sales.
As at 31 December 2023, there are no contract assets or contract liabilities
outstanding (2022: nil).
3 Finance income/(costs) Year Year
ended ended
31 December 31 December
2023 2022
£000 £000
Finance income:
Interest on short-term deposits 24 8
Net foreign exchange gain 153 -
Finance income 177 8
Finance costs:
Interest on borrowings (909) (950)
Amortisation of finance fees on borrowings (268) (268)
Net foreign exchange loss - (1,417)
Unwinding of discount on decommissioning provision (note 10) (2,596) (1,749)
Interest charge on lease liability (727) (707)
Other interest payable (103) -
Finance costs (4,603) (5,091)
4 Income tax
(i) Tax charge/(credit) on profit/(loss) from continuing ordinary activities Year ended Year ended
31 December 31 December
2023 2022
£000 £000
Current tax:
Charge for the year 1,099 -
Total current tax charge 1,099 -
Deferred tax:
Charge/(credit) relating to the origination or reversal of temporary 8,611 (8,160)
differences
Charge due to tax rate changes - 1,465
(Credit)/charge in relation to prior years (1,450) 57
Total deferred tax charge/(credit) 7,161 (6,638)
Total income tax charge/(credit) 8,260 (6,638)
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% (2022: 40%), in addition to the Energy Profit Levy (EPL)
introduced in May 2022 with an average rate of 35% for the year (2022: 15%).
A reconciliation of the UK statutory corporation tax rate (applicable to oil
and gas companies) applied to the Group's profit/(loss) before tax to the
Group's total tax charge/(credit) is as follows:
Year ended Year ended
31 December 31 December
2023 2022
£000 £000
Profit/(loss) from continuing ordinary activities before tax 2,769 (18,416)
Expected tax charge/(credit) based on profit/(loss) from continuing ordinary 2,077 (10,141)
activities multiplied by an average combined rate of corporation tax and
supplementary charge and Energy Profit Levy in the UK of 75% (2022: 55%)
Deferred tax (credit)/charge in respect of prior years (1,450) 57
Expenses not allowable for tax purposes 1,502 2,105
Differences in amounts not allowable for supplementary charge purposes* (29) (100)
Impact of profits or losses taxed or relieved at different rates 1,218 4,499
Net increase/(decrease) in unrecognised losses carried forward 5,178 (1,864)
Net decrease in unrecognised temporary taxable differences (236) (2,659)
Tax rate change - 1,465
Tax charge/(credit) on profit/(loss) from continuing activities 8,260 (6,638)
* 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:
2023
£000 2022
£000
Asset at 1 January 44,813 38,176
Tax credit/(charge) relating to prior year 1,450 (57)
Tax (charge)/credit during the year (8,611) 8,160
Tax charge arising due to the changes in tax rates - (1,465)
Deferred tax arising from business combination (note 11) (454) -
Other (6) (1)
Asset at 31 December 37,192 44,813
The following is an analysis of the deferred tax asset by category of
temporary difference:
31 December 31 December
2023 2022
£000 £000
Accelerated capital allowances (25,321) (20,685)
Tax losses carried forward 44,388 50,659
Investment allowance unutilised 2,051 2,265
Decommissioning provision 15,737 12,524
Unrealised gains or losses on derivative contracts - (394)
Share-based payments 68 155
Right-of-use asset and liability 269 289
Deferred tax asset 37,192 44,813
iv) Tax losses
The Group has gross total tax losses and similar attributes carried forward of
£362.1 million (2022: £355.3 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 £109.5 million (2022:
£123.2 million) of ringfence corporation tax losses which will be recovered
at 30% of future taxable profits, £92.6 million (2022: £119.8 million) of
supplementary charge tax losses which will be recovered at 10% of future
taxable profits and £4.3 million (2022: £1.9 million) of losses arising
under the EPL regime which will be recovered at 35% of future taxable
profits.
v) Changes in legislation
In March 2024, the UK Government announced that the sunset clause for EPL
would be extended by a year to 31 March 2029, however this has not yet been
enacted at the date of approval of the financial statements. Once enacted, the
extension in the sunset clause for EPL will have an impact on the tax charge
and deferred tax asset to be recognised in future periods. The Group will
continue to monitor developments and any potential related impacts in this
regard.
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 £4.5
million (2022: a loss after taxation attributable to ordinary equity holders
of the Parent Company of £11.8 million) and the weighted average number of
ordinary shares outstanding during the year of 127.7 million (2022: 125.9
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 2023, there are 7.5 million potentially dilutive share
options (31 December 2022: 11.9 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
2023 2022
Basic loss per share - ordinary shares of 0.002 pence each (3.52p) (9.35p)
Diluted loss per share - ordinary shares of 0.002 pence each (3.52p) (9.35p)
Loss for the year attributable to equity holders of the Parent Company - £000 (4,493) (11,778)
Weighted average number of ordinary shares in the year- basic EPS 127,671,520 125,923,609
Weighted average number of ordinary shares in the year- diluted EPS 127,671,520 125,923,609
6 Intangible assets
2023 2022
Exploration and evaluation assets Development costs Goodwill Total Exploration and evaluation assets Development costs Goodwill Total
£'000 £'000 £'000 £'000 £'000 £'000 £'000 £'000
At 1 January 5,558 3,710 - 9,268 34,844 3,478 - 38,322
Additions 553 705 - 1,258 722 232 - 954
Amounts recognised on acquisition of a subsidiary (note 11) - 2,529 1,311 3,840 - - - -
Exchange differences - 28 15 43 - - - -
Changes in decommissioning - - - - 10 - - 10
Impairment (456) - (130) (586) (30,018) - - (30,018)
At 31 December 5,655 6,972 1,196 13,823 5,558 3,710 - 9,268
Exploration and evaluation assets
Exploration costs written off in the financial year to 31 December 2023 were
£0.5 million (2022: £30.0 million) which included £0.3 million of early
stage projects relating to our conventional assets where there is no further
development prospect and £0.2 million related to trailing costs on previously
impaired unconventional licences.
The 2022 exploration costs written off related to unconventional licences
where the Board concluded it was unlikely that the Group would be able to
proceed with the commercial development of these assets. This was due to the
rejection of planning consent at Ellesmere Port, and the reintroduction of the
moratorium on hydraulic fracturing for shale gas by the UK Government in
October 2022.
The Group has £5.7 million (2022: £5.6 million) of capitalised exploration
expenditure remaining, which relates to our conventional assets including PL
235 and 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 (note 11) during the year. Following the acquisition, the
Group identified five 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
four licences (either awarded or under application) with the Croatian
government (Ernestinovo, Sječe, Pčelić, and Leščan), in addition to the
previously identified CGU relating to the UK geothermal business. The
carrying amount of goodwill has been allocated to the following CGUs:
:
31 December 2023 31 December 2022
£000 £000
Sječe licence 369 -
Pčelić licence 368 -
Ernestinovo licence 459 -
1,196 -
On the date of the acquisition (note 11), goodwill of £0.1 million (2022:
£nil) was allocated to the Leščan CGU, reflecting the potential of being
awarded this licence. Given that this licence was not awarded to the Group,
this goodwill has been fully impaired. No goodwill has been allocated to the
UK geothermal business CGU.
The Group tests goodwill for impairment annually or more frequently if there
are indications that goodwill might be impaired. The Group reviewed the
carrying value of the Sječe licence and Pčelić licence CGUs at 31 December
2023 and assessed them for impairment. The recoverable amount for these CGUs
were based on fair value less costs of disposal (FVLCD). Due to the proximity
in time of the acquisition of A14 Energy Limited which resulted in the
origination of the goodwill amount, to the balance sheet date and due to the
limited activity undertaken on these licences between the award date of the
licences and the balance sheet date, the FVLCD of these CGUs was assessed as
being consistent with the consideration paid by the Group on acquisition. As a
result, no impairment charge was recognised against goodwill allocated to
these two CGUs during the current year. The Group also reviewed the carrying
value of the Ernestinovo licence CGU (which includes the related goodwill) at
31 December 2023, as further detailed below, with no impairment charge being
recognised against goodwill allocated to this CGU in the current year.
Development costs
The 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 during the current year (see note 11).
The carrying amount of development costs is split between CGUs as follows:
31 December 2023 31 December 2022
£000 £000
UK geothermal business 4,415 3,710
Ernestinovo licence 2,557 -
6,972 3,710
Development costs relating to UK Geothermal business
The costs relate 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.
The Group reviewed the carrying value of development costs as at 31 December
2023 and assessed it for impairment. The development of the Stoke-on-Trent
project has taken longer than anticipated. This was initially due to COVID-19
related delays and the delay in the Government establishing a replacement for
the Renewable Heat Incentive scheme which expired in March 2021. However, in
March 2022, the UK Government launched the Green Heat Network Fund ("GHNF")
confirming that it will fund up to 50% of a project's total combined
commercialisation and construction costs and a grant funding application was
submitted by GT Energy jointly with SSE in the second half of 2022. SSE have
since refined their commercial model and undertaken further discussions with
the council and other stakeholders along with appointing a third-party
consultant to perform a project due diligence. This due diligence was
conducted during the year and the technical and commercial aspects of the
geothermal heat provision within the project were signed off by the consultant
towards the end of Q3 2023. Subsequent to the year end, SSE, as lead applicant
have submitted a project change request to the GHNF which seeks to amend both
the capital grant as well as the timetable within which that grant will be
spent. A decision is expected in the second quarter of 2024.
Although the development of the project has been delayed, this does not
materially impact the overall economics and, therefore, no impairment of
development costs relating to the UK Geothermal business has been recognised
for the year (2022: £nil). The recoverable amount of the CGU is based on its
value in use and amounts to £6.1 million. The principal assumptions are the
heat sale volumes, unit price and discount rate. A 10% reduction in sales
volume would result in a decline of the recoverable amount by £1.9 million. A
10% reduction in price would result in a decline of the recoverable amount by
£2.1 million. An increase in the discount rate assumed of 1% (from 9.9% to
10.9%) would result in a decline of the recoverable amount by £1.9 million.
Development costs relating to Ernestinovo licence
The development costs associated with Ernestinovo relate to the fair value of
assets acquired as part of the A14 Energy acquisition as explained in note 11.
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 reviewed the carrying value of the Ernestinovo licence CGU as at 31
December 2023 and assessed it for impairment. The recoverable amount for the
CGU was based on fair value less costs of disposal (FVLCD). Due to the
proximity in time of the acquisition of A14 Energy Limited which resulted in
this origination of this asset to the balance sheet date and the limited
change in the value of the CGU by year end, the FVLCD of the CGU was assessed
as being consistent with the consideration paid by the Group on acquisition.
Therefore, no impairment charge has been recognised against the capitalised
development cost on the Ernestinovo licence CGU during the year.
7 Property, plant and equipment
2023 2022
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 220,301 2,046 222,347 215,222 2,430 217,652
Additions 6,920 27 6,947 7,757 79 7,836
Disposals/write-offs - (339) (339) - (463) (463)
Changes in decommissioning* (333) - (333) (2,678) - (2,678)
At 31 December 226,888 1,734 228,622 220,301 2,046 222,347
Accumulated Depreciation, Depletion and Impairment
At 1 January 147,022 594 147,616 142,034 1,035 143,069
Charge for the year 6,982 30 7,012 5,020 22 5,042
Disposals/write-offs - - - - (463) (463)
Impairment - - - 10,457 - 10,457
Impairment reversal - - - (10,489) - (10,489)
At 31 December 154,004 624 154,628 147,022 594 147,616
NBV at 31 December 72,884 1,110 73,994 73,279 1,452 74,731
*The decommissioning asset reduced in line with the decommissioning liability
following a review of the estimate at 31 December 2023 (note 10).
Capital expenditure incurred during the year mostly related to purchase of
long lead items and site preparation required for an intended upcoming
development project at Corringham, capital spend relating to improvement works
at the Holybourne site 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 2023
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.
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:
31 December 2023
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
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 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 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 2023 are shown below:
CGU 10% reduction in price 10% reduction in production USD/GBP foreign exchange rate @ $1.4 Increase in discount rate by 1%
£m £m £m £m
North (8.57) (9.03) (6.28) (1.62)
South (7.31) (7.23) (7.36) (2.52)
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.
Year ended 31 December 2022
At 30 June 2022, due to the high oil and gas prices and favourable foreign
exchange rates, management identified impairment reversal indicators for the
North and South CGUs and performed a detailed exercise to determine the amount
of reversal at that date. Due to subsequent increases in interest rates, the
imposition of the Energy Profits Levy and a reduction in commodity price
forward curves in the second half of 2022, management identified impairment
indicators at the North and South CGUs and performed an impairment assessment
as at 31 December 2022.
The Scotland CGU was undergoing a redevelopment plan. Possible increased
development costs under the plan indicated a potential impairment for this CGU
leading to an impairment assessment being performed at 30 June 2022. No
further impairment assessment was performed at year end, given no impairment
indicators were identified at 31 December 2022.
The future cash flows in the impairment assessments at 30 June 2022 and 31
December 2022 were estimated using the following key assumptions:
31 December 2022 30 June 2022
Oil price (Brent) $80-$70/bbl for the years 2023-2027 and $65/bbl thereafter $100-$80/bbl for the years 2022-2026 and $65/bbl thereafter
USD/GBP foreign exchange rate Range of $1.22:£1.00 - $1.30:£1 Range of $1.25:£1.00 - $1.35:£1
Post-tax discount rate 10.5% 9%
Outcome of impairment reviews:
The 30 June 2022 impairment assessment resulted in a recoverable amount
greater than the carrying amount by £16.0 million in the South CGU
(recoverable amount of £44.8 million) and £0.8 million in the North CGU
(recoverable amount of £39.7 million). We capped the impairment reversal
recorded in the South CGU to £10.5 million, comprising the net book value of
the full amount previously impaired, in line with the requirements of IAS 36.
No impairment reversal was recorded in the North CGU as reasonable downside
cases indicated that an impairment could be required if certain 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, an impairment of £1.5 million was recognised as at 30
June 2022 (with a recoverable amount of £1.3 million), as it was not expected
that all past costs would be recovered through the development of the site.
The 31 December 2022 impairment assessment resulted in an impairment in the
North CGU of £8.9 million, with a final recoverable amount of £34.5 million.
However, in the South CGU, the recoverable amount increased to £45.9 million
as a result of a change in the reserves profile, hence no impairment was
recorded.
8 Cash and cash equivalents
31 December 31 December
2023 2022
£000 £000
Cash at bank and in hand 3,855 3,092
The cash and cash equivalents do not include restricted cash.
Restricted cash
31 December 31 December
2023 2022
£000 £000
Current 410 -
Non-current - 410
The restricted cash represents restoration deposits paid to Nottinghamshire
County Council, which serve as collateral for the restoration of drilling
sites at the end of their life. The restoration deposits are subject to
regulatory and other restrictions and are therefore not available for general
use of the Group. These are expected to be collected within the next 12 months
based on the timing of the completion of related site restoration activities
and have therefore been presented within current assets.
Net debt reconciliation
31 December 31 December
2023 2022
£000 £000
Cash and cash equivalents 3,855 3,092
Borrowings - including capitalised fees (5,358) (8,743)
Net debt (1,503) (5,651)
Capitalised fees (133) (401)
Net debt excluding capitalised fees (1,636) (6,052)
2023 2022
Cash and cash equivalents Borrowings Total Cash and cash equivalents Borrowings Total
£000 £000 £000 £000 £000 £000
Net debt as at 1 January 3,092 (8,743) (5,651) 3,289 (14,836) (11,547)
Interest paid on borrowings (809) - (809) (950) - (950)
Other Interest paid (575) - (575) - - -
Repayment of RBL (note 9) (3,284) 3,284 - (7,985) 7,985 -
Foreign exchange adjustments (230) 369 139 217 (1,624) (1,407)
Other cash flows 5,661 - 5,661 8,521 - 8,521
Other non-cash movements - (268) (268) - (268) (268)
Net debt as at 31 December 3,855 (5,358) (1,503) 3,092 (8,743) (5,651)
9 Borrowings
31 December 31 December
2023 2022
£000 £000
Reserve-Based Lending Facility (RBL) - secured (current) (5,358) (3,325)
Reserve-Based Lending Facility (RBL) - secured (non-current) - (5,418)
(5,358) (8,743)
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.
Reserves-Based Lending Facility
In October 2019, the Group signed a $40.0 million RBL facility with BMO
Capital Markets (BMO). In addition to the committed $40.0 million RBL, a
further $20.0 million is available on an uncommitted basis, and can be used
for any future acquisitions or new conventional developments. The RBL has a
five-year term, an interest rate of USD LIBOR plus 4.0%, matures in June 2024
and is 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.
As at 31 December 2023, we had an available facility limit of $7.0 million, in
line with the loan facility amortisation schedule. The current portion of the
borrowings have been assessed on the basis of the RBL loan facility amortising
in line with the contractual terms and being fully repayable within a period
of next twelve months.
We made a repayment on the loan of £3.3 million during the year (2022: £8.0
million).
Under the terms of the RBL, the Group is subject to a financial covenant
whereby, as at 30 June and 31 December each year, the ratio of Group Net Debt
at the period end to Group Earnings before Interest, Tax, Depreciation,
Amortisation and Exceptional items ("EBITDAX" as defined in the RBL agreement)
for the previous 12 months shall be less than or equal to 3.5:1. The Group
complied with its covenants for the financial years ended 31 December 2023 and
31 December 2022.
On 9 April 2024, the Group announced the closing of a new €25.0 million
facility with Kommunalkredit Austria AG (Kommunalkredit), which was used to
repay the outstanding balance on the RBL facility, in addition to providing
funding for the Group's geothermal development activities (see note 12).
Collateral against borrowing
A Security Agreement was executed between BMO and Star Energy Group plc and
some of its subsidiaries, namely; Island Gas Limited, Island Gas Operations
Limited, Star Energy Weald Basin Limited, IGas Energy Limited, Star Energy
Limited, Island Gas (Singleton) Limited, Dart Energy (East England) Limited,
Dart Energy (West England) Limited, IGas Energy Development Limited, IGas
Energy Enterprise Limited, Dart Energy (Europe) Limited and IGas Energy
Production Limited.
Under the terms of this Agreement, BMO has a floating charge over all of the
assets of these legal entities, other than property, assets, rights and
revenue detailed in a fixed charge. The fixed charge encompasses the Real
Property (freehold and/or leasehold property), the specific petroleum
licences, all pipelines, plant, machinery, vehicles, fixtures, fittings,
computers, office and other equipment, all related property rights, all bank
accounts, shares and assigned agreements and rights including related property
rights (hedging agreements, all assigned intergroup receivables and each
required insurance and the insurance proceeds).
10 Provisions
2023 2022
Decommissioning provisions Contingent consideration Total Decommissioning provisions Contingent consideration Total
£'000 £'000 £'000 £'000 £'000 £'000
At 1 January (62,825) (2,731) (65,556) (65,995) (2,731) (68,726)
Acquisitions (note 11) - (857) (857) - - -
Utilisation of provision 2,909 857 3,766 2,251 - 2,251
Unwinding of discount (note 3) (2,596) - (2,596) (1,749) - (1,749)
Reassessment of decommissioning provision 101 - 101 2,668 - 2,668
At 31 December (62,411) (2,731) (65,142) (62,825) (2,731) (65,556)
2023 2022
Decommissioning provisions Contingent consideration Total Decommissioning provisions Contingent consideration Total
£'000 £'000 £'000 £'000 £'000 £'000
Current (1,956) (280) (2,236) (6,560) (280) (6,840)
Non-current (60,455) (2,451) (62,906) (56,265) (2,451) (58,716)
At 31 December (62,411) (2,731) (65,142) (62,825) (2,731) (65,556)
Decommissioning provision
The Group spent £2.9 million on decommissioning activities during the year
(2022: £2.3 million) related primarily to plugging and abandoning wells at
the Springs Road, Ince Marshes and Egmanton 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 29 years from year end (2022: 1 to 30
years). The provisions are based on the Group's internal estimate as at 31
December 2023. 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
2024-2027 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 and gas 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 near term for
the period 2023 - 2025 and thereafter incorporates the long term UK target
inflation rate for the period 2026 and beyond.
The discount rate used in the provision calculation as at 31 December 2023
ranged from 3.0% to 5.5% (2022: 3.0% to 5.1%). The increase in the risk free
discount rate during the year is mainly due to the increase in the yield on UK
government bond for periods comparable to the life of the provision.
At 31 December 2023, the Group reassessed the decommissioning provision which
resulted in a reduction of £0.1m to the value of the liability. The change
comprises a £0.4m decrease due to the change in the discount rate, and a
£2.5m decrease due to expected timing, offset by expected cost (including
inflationary) increases of £2.8m.
Sensitivity of changes in assumptions
Management performed sensitivity analysis to assess the impact of changes to
the risk free rate and short term inflation assumption 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
£4.0 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
£6.3 million.
Contingent consideration
The contingent consideration at the balance sheet date relates to the amount
arising on the acquisition of GT Energy UK Limited. The contingent
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 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. The fair value of the
consideration for each milestone recognised was calculated by determining the
probability weighted value of each payment and discounted using a WACC of
8.3%. In addition, there is a business development milestone relating to
securing and achieving targets for a second geothermal project or generating
additional capacity for the Stoke-on-Trent project. The acquisition agreement
and economic model assumed the availability of the Renewable Heat Incentive
(RHI), which closed to applications from 31 March 2021. In March 2022, the
UK Government launched the GHNF and we have applied for funding for the
Stoke-on-Trent project in the first round. The change in nature of the
government support for the project is not provided for in the economic model
or the SPA. Whilst the contractual implications on the acquisition agreement
are being assessed, management believes that the current value provides the
best estimate of the contingent consideration at this time. The estimated fair
value will be reviewed as the project progresses and more information becomes
available.
The consideration on the acquisition of an interest in A14 Energy Limited
(note 11) included contingent consideration of £0.9 million 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.
11 Acquisition of a subsidiary
Acquisition of A14 Energy Limited
On 25 August 2023, the Group acquired 51% of the issued share capital of A14
Energy Limited ("A14 Energy"), thereby obtaining control of A14 Energy. At the
date of acquisition, A14 Energy owned, via its Croatian subsidiary, IGeoPen
d.o.o ("IGeoPen"), the Ernestinovo geothermal waters exploration licence in
the highly prospective Pannonian Basin in Croatia. A14 Energy qualified as a
business as defined in IFRS 3 Business Combinations, as the acquired workforce
contained significant skills, knowledge and experience in the Croatian
geothermal market and the business processes formed a substantive process.
This transaction further develops the Group's strategy to transition into a
geothermal developer, owner and operator, diversifying regulatory risk and
providing an entry into the electricity generation sector.
The amounts recognised in respect of the fair value of the identifiable assets
acquired and liabilities assumed are set out in the table below:
31 December
2023
£000
Cash and cash equivalents 11
Intangible assets- Development costs (see (a) below) 2,529
Deferred tax liabilities (454)
Trade and other payables (5)
Total identifiable assets acquired and liabilities assumed 2,081
Goodwill (see (b) below) 1,311
Non-controlling interest in A14 Energy (49% equity interest) (see (d) below) (1,242)
Amounts recognised upon acquisition 2,150
Satisfied by:
Cash consideration 1,293
Contingent consideration (see (c) below) 857
Total consideration transferred 2,150
(a) An intangible asset of £2.5 million has been recognised in respect of the
value of the Ernestinovo licence award and work performed (including a
comprehensive subsurface study and geological modelling) up to the acquisition
date in progressing with the re-entry of an existing well on the Ernestinovo
exploration licence. The fair value of the capitalised development costs was
determined using the market approach. Taking into account the characteristics
of the assets and liabilities acquired in an orderly transaction between two
market participants, management has concluded that the consideration
transferred equals the fair value of the share of the business acquired by the
Group, thus allowing the fair value of the intangible assets acquired to be
calculated.
(b) Of the goodwill of £1.3 million arising from the acquisition, £0.9
million is attributable to the potential benefits of application bids in
progress for the Sječe, Pčelić, and Leščan exploration licences on the
acquisition date. Although there was potential future economic benefit arising
from the work completed on these applications at the acquisition date, this
did not meet the definition of an asset as the bids had not been awarded and
were not under the control of the acquired entity. The remaining £0.4 million
of goodwill is attributable to the deferred tax implications associated with
the capitalised development cost acquired in respect of the Ernestinvo
exploration licence. The goodwill recognised is not expected to be deductible
for income tax purposes (see note 6).
(c) The contingent consideration arrangement required Star Energy to pay an
additional amount of £0.4 million for each of the in-progress licence bids
awarded after the acquisition date. The outcome of these bids was announced in
October 2023 confirming that the bids at Sječe and Pčelić had been
successful (but the bid at Leščan was unsuccessful) and therefore a payment
of £0.9 million became due. The fair value of the contingent consideration on
the date of acquisition was estimated based on the assessed likelihood of the
successful award of each bid.
(d) The non-controlling interest (49% equity interest in A14 Energy)
recognised at the acquisition date was measured by reference to the
non-controlling interests' proportionate share of the fair value of the
acquiree's identifiable net assets and amounted to £1.2 million.
Acquisition-related costs (included in administrative expenses) amounted to
£0.5 million.
A14 Energy contributed £nil revenue and loss of £2.0 million to the Group's
profit before tax for the period between the date of acquisition and the
reporting date. The loss in the period arose mainly as a result of costs
incurred in relation to the re-entry on the Ernestinovo well including rig
cost and well site and test pit construction costs. If the acquisition of A14
Energy had been completed on the first day of the financial year, Group
revenues and losses would be materially consistent with those reported.
12 Subsequent events
On 9 April 2024, the Group announced the closing of a new €25 million
facility with Kommunalkredit Austria AG (Kommunalkredit), comprising of a
facility A which was used to fund the repayment of the outstanding balance on
the RBL facility and a facility B which provides funding the Group's
geothermal development activities. Facility A carries a fixed interest rate of
9.384% and is repayable on 30 June 2025; facility B carries an interest rate
of Euribor + 6% and has a 5 year term with repayments commencing on 31
December 2025.
A security agreement was executed between Apex Corporate Trustees (UK) Limited
(as security agent for Kommunalkredit) ("Apex"), the Parent Company and some
of its 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. 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 (as "Scottish Chargors").
Under the terms of the security agreement, Apex has a fixed charge 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. Apex also has a first floating charge
over property, assets, rights and revenues (other than those charged or
assigned pursuant to the aforementioned fixed charge). Under the Scottish
bonds and floating charges' terms, Apex has a first floating charge over all
of the assets of the Scottish Chargors.
The new facility agreement carries certain financial covenants which have been
considered in the preparation of the going concern assessment performed by the
Directors as part of the preparation of the Group's consolidated financial
statements.
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