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

* 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).

*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.

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.

* Rounds to nil

** Includes depreciation charge recorded in administrative expenses

* 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).

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

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

FOR THE YEAR ENDED 31 DECEMBER 2023

CONSOLIDATED BALANCE SHEET

AS AT 31 DECEMBER 2023

CONSOLIDATED BALANCE SHEET (CONTINUED)

AS AT 31 DECEMBER 2023

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

*     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

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:

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).

4 Income tax

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:

* 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:

The following is an analysis of the deferred tax asset by category of temporary difference:

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:

6 Intangible assets

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: 

: 

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:

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

\* 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:

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:

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:

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

The cash and cash equivalents do not include restricted cash. 

Restricted cash

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

9 Borrowings

The carrying amounts of each of the Group's financial liabilities included within borrowings are considered to be a reasonable approximation of their fair value.

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

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:

(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.