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
76.7km2 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
31
December
2023
£000
|
Year
ended
31
December 2022
£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
31
December
2023
£000
|
Year
ended
31
December
2022
£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
2023
£000
|
31
December
2022
£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
2023
£000
|
31
December
2022
£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
capital
£000
|
Share
premium
account
£000
|
Foreign
currency
translation
reserve*
£000
|
Other
reserves**
£000
|
Accumulated deficit
£000
|
Equity
attributable to owners of the Company £000
|
Non-controlling Interest
(note
11)
£000
|
Total
equity
£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
31 December
2023
£000
|
Year
ended
31
December 2022
£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
31
December
2023
£000
|
Year
ended
31
December
2022
£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
ended
31
December
2023
£000
|
Year
ended
31
December
2022
£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
31
December
2023
£000
|
Year
ended
31
December
2022
£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 differences
|
8,611
|
(8,160)
|
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
31
December
2023
£000
|
Year
ended
31
December
2022
£000
|
Profit/(loss) from continuing
ordinary activities before tax
|
2,769
|
(18,416)
|
Expected tax charge/(credit) based
on profit/(loss) from continuing ordinary activities multiplied by
an average combined rate of corporation tax and supplementary
charge and Energy Profit Levy in the UK of 75% (2022: 55%)
|
2,077
|
(10,141)
|
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
2023
£000
|
31
December
2022
£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
31
December
2023
|
Year
ended
31
December
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
£'000
|
Development
costs
£'000
|
Goodwill
£'000
|
Total
£'000
|
|
Exploration and evaluation assets
£'000
|
Development costs
£'000
|
Goodwill
£'000
|
Total
£'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
£000
|
31
December 2022
£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
£000
|
31
December 2022
£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
assets
£'000
|
Other property, plant and
equipment
£'000
|
Total
£'000
|
|
|
Oil and
gas
assets
£'000
|
Other
property, plant and equipment
£'000
|
Total
£'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
2023
£000
|
31
December
2022
£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
2023
£000
|
31
December
2022
£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
2023
£000
|
31
December
2022
£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
2023
£000
|
31
December
2022
£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
£'000
|
Contingent
consideration
£'000
|
Total
£'000
|
|
Decommissioning provisions
£'000
|
Contingent consideration
£'000
|
Total
£'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
£'000
|
Contingent
consideration
£'000
|
Total
£'000
|
|
Decommissioning provisions
£'000
|
Contingent consideration
£'000
|
Total
£'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.