Star Energy Group - Interim Results

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION

13 September 2023

Star Energy Group plc (AIM: STAR)

("Star Energy" or "the Company" or "the Group")

Unaudited Interim results for the six months ended 30 June 2023

Star Energy announces its unaudited interim results for the six months to 30 June 2023.

Commenting today Chris Hopkinson, Chief Executive Officer, said:

"We have delivered a strong operating performance in the first half with average net production of 2,071 boepd compared to 1,865 in 2022.  We are working hard to reduce our operating costs where possible, in the face of general cost inflation and ever-increasing regulatory overburden.

Maximising returns from our conventional oil and gas business remains a key focus for us, given its free cash generation, particularly with improving commodity prices.  That, coupled with decades of experience of sub-surface analysis, onshore drilling, well management and environmental control from our portfolio will play a key role in our geothermal development.

The global potential for geothermal, as a zero carbon source of energy, is clear.

In the UK we are building a material pipeline of business opportunities in both the private and public sector.  The recently released Government commissioned white paper, produced by the British Geological Survey (BGS) and ARUP, highlights the significant opportunity that exists to decarbonise the NHS estate and we have already won tenders for two NHS Trusts in Manchester and Salisbury.

The recent acquisition in Croatia represents a significant opportunity to accelerate our development and enables us to diversify into geothermal electricity generation. The Croatian Government is highly supportive and the electricity market is liberalised and well established offering an attractive market premium (CfD) for a 12 year period.

This is an important next step in our strategy to transition, over time, into a significant player in the geothermal market and to deliver future value for our shareholders."

Results Summary

*these are alternative performance measures which are further detailed in the financial review

Corporate & Financial Summary

·    Company rebranding complete.

·    Strategic acquisition of Croatian geothermal development business

o  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.

·    Consistently strong production in H1 2023 offset by lower commodity prices compared to H1 2022. Brent prices averaged $79.8/bbl in H1 2023 compared to $107.6/bbl in H1 2022.

·    Cash balances as at 30 June 2023 were £1.5 million (31 December 2022: £3.1 million) with net debt of £4.0 million (31 December 2022: £6.1 million). We had headroom of US$4.7 million (£3.7 million) under our RBL as at 31 August 2023.

·    Operating cash flow before working capital movements and realised hedges in H1 2023 of £8.5 million (H1 2022: £16.4 million).

·    £4.4 million of net cash capex incurred during six months to 30 June 2023.  Net cash capex for FY 2023 expected to be £10.0 million, primarily relating to our conventional assets including expenditure on near-term incremental projects, our Corringham development, as well as costs related to complying with and reducing the regulatory burden at some of our sites.

·    The Group benefited from its hedging policy with 60,000 bbls hedged in the period at an average of $95.0/bbl resulting in a realised gain of £0.7 million.

·    Profit after tax of £0.5m (H1 2022 £19.4 million) was after deducting a tax charge of £3.7 million (H1 2022 tax credit of £13.2 million). The tax charge relates primarily to non-cash deferred tax. The estimated Energy Profits Levy for the period ended 30 June 2023 is c.£0.9 million which is payable in October 2024.

·    Ring fence tax losses of £259 million.

Operational Summary

·    Net production averaged 2,071 boepd in H1 2023 (H1 2022: 1,865 boepd).  

·    Full year net production remains on track. Underlying cash operating costs per boe anticipated to be c.$39.5/boe (based on an average exchange rate of £1:$1.26).

·    Planning permission granted for Glentworth oil project.

·    Corringham site construction nearing completion, securing planning.

·    Awarded two NHS hospital trust geothermal projects in Manchester and Salisbury

o  2D seismic survey for Salisbury project planned.

·    Two Government sponsored geothermal reports published, endorsing its potential as a future renewable energy source and highlighting the potential for geothermal in the decarbonisation of the NHS estate.

·    There is no update on the status of the grant funding for the Stoke-on-Trent geothermal project at this time. 

A results presentation will be available at https://www.starenergygroupplc.com/investors/reports-publications-presentations

Qualified Person's Statement

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

Frances Ward, Chief Financial 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

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

Introduction

The first half of the year has been a busy one for the Company with strong production from its conventional assets, development of new oil and gas projects, progress on the abandonment programme and a number of new geothermal contracts won, specifically with the NHS.

The streamlining of the management structure and rebranding of the Company from IGas Energy plc to Star Energy Group plc, which is now complete, were important steps in refocussing resource and redefining the Company's strategic direction. 

The Group has significant intrinsic value in its oil and gas portfolio, from the existing producing assets, where the focus is optimisation, from the portfolio of near term development opportunities that can give rise to a step change in production and from the significant ring fenced tax loss position.  Whilst our focus is on delivering this value from our existing conventional assets, the Group 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, a factor that is allowing us to develop a market leading position in the provision of geothermal heat in the UK. 

Globally, the move to geothermal as a zero carbon source of energy continues to grow apace.  There is a significant opportunity in the UK, in particular in decarbonising energy sources throughout the public sector estate. Whilst the Company spearheads the industry in the UK, it is keen to widen its footprint, diversify into electricity generation and accelerate its transition, as evidenced by the recent acquisition of A14 Energy Ltd (A14) in Croatia.

Board Changes

In January 2023, Doug Fleming joined the Board as an Independent Non-executive Director and became a member of the audit committee.  Doug was most recently Chief Financial Officer at private equity backed Siccar Point Energy, an E&P company with assets in the UK sector of the North Sea.

In June, Chris Hopkinson was appointed as Chief Executive Officer  of the Company.  Chris joined Star Energy in January 2022 and, since September 2022, had assumed the role of Interim Executive Chairman.

Also in June, Philip Jackson was appointed as Non-executive Chairman.  Philip has been a Non-executive Director of the Company since 2017.

Production Operations

Net production for the period averaged 2,071 boepd (H1 2022: 1,865 boepd), with maximum uptime from wells and we anticipate net production will remain, as forecast, at around 2,000 boepd for the full year.

We continue to focus our technical and operational expertise on maintaining and increasing our production, whilst reducing operating costs where we can.  This is achieved through the execution of incremental production opportunities that demonstrate commercial benefit via our delivery assurance processes and streamlining our operations.  This allows decision making within the operational assets and has resulted in the execution of a successful well stimulation campaign, at low cost and high return, and increased well uptime across the portfolio. Operating costs per barrel of oil equivalent produced have reduced despite general inflation, increasing regulation and excessive delays in obtaining regulatory approval for relatively standard environmental permits.

Operating cash flow before working capital movements is expected to be c.£13.0 million in 2023 based on a forecast average oil price of $85/bbl for the remainder of the year.

Reserves and resources

CPR

In February 2023, Star Energy announced the publication of the full and final results of the Competent Persons Report (CPR) by DeGolyer & MacNaughton (D&M), a leading international reserves and resources auditor.

The report comprised an independent evaluation of Star Energy's conventional oil and gas interests as of 31 December 2022. The full report can be found here: https://www.starenergygroupplc.com/investors/reports-publications-presentations

Star Energy Group Net Reserves & Contingent Resources as at 31 Dec 2022 (MMboe).

*Oil price assumption of c.$75/bbl for 5 years, then inflated at 2% p.a. from 2031 (capped at $118/bbl)

1P NPV10 of $144 million(2021: $139 million): 2P NPV10 of $215 million (2021: $190 million)*

Development Assets

Oil and Gas

In April, 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 bbls/d 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 with the subsequent development having the potential to add an additional 500 bbls/d 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 for the project which are required before development can commence, were submitted to the Environment Agency in October 2022 and are expected to be issued before the end of 2023.

The extensive site upgrades required to drill an additional well at Corringham are nearing completion. Phase 1 of the Corringham project is now able to be executed immediately, subject to funding, developing c.350 Mstb of 2P undeveloped reserves.  Initial production is expected to be 110 bopd.  The success of Phase 1 of the project unlocks Phase 2 which would develop c.935 Mstb of current 2C resources.

Our gas to wire project at Bletchingley, which has full planning consent and a secured grid connection, awaits its environmental permits from the Environment Agency.  The permit application was submitted in July 2022 and we expect that these will be issued in 2023.

All of these projects have very strong economics, both increasing production and bringing field wide operational efficiencies.  The further progress of these projects remains subject to overcoming the excessive delays in obtaining environmental permits from the Environment Agency for what are relatively straightforward permits, similar to many others already in place, the availability of free cash flow, capital allocation decisions and the availability of additional financing, and we continue to assess our options in this regard.

In the first half of 2023, we have fully abandoned three wells and geologically abandoned a further three.  We will be moving to abandon the Springs Road well in the second half of the year.  Despite cost inflation on specific materials, services and labour, through a three well abandonment campaign we have seen well on well cost reduction nearing 10%. 

Geothermal

UK

We have made significant progress in bringing our vision for decarbonisation of large-scale heat using geothermal energy in the UK closer to fruition, working closely with the Government, academia and commercial partners to accelerate support for, and understanding of, this proven technology.

In June 2023, the BGS in collaboration with Arup, produced a White Paper[1] which 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 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 has developed a market leading position in this area, having been successful in both of the two tenders awarded to conduct detailed feasibility studies into supplying renewable heat to NHS Trusts.  These were awarded following five tenders run by the Carbon and Energy Fund (CEF).  A further three bids were submitted and the results are awaited.  These feasibility studies are the first phase of partnerships with the respective NHS Trusts, which, if successful, will see the hospitals being supplied with deep geothermal heat on long-term offtake agreements. 

The tenders successfully awarded are:

-      Salisbury NHS Foundation Trust - to deliver a geothermal heat solution for Salisbury District Hospital. Work has already begun to de-risk and develop the geothermal project from initial geological feasibility with a 2D seismic survey planned.  Once data is analysed and models constructed, the project will move through consenting, to construction of the wells and energy centre.  It is expected that heat supply will begin in early 2026 subject to normal planning, regulatory permitting and procurement cycles.  It is envisaged that Star Energy will own and operate the facility.

-      Manchester University NHS Foundation Trust - to undertake a feasibility study of supplying the Wythenshawe Hospital with heat from a deep geothermal system. An Innovation Partnership with the Trust and the CEF will be created to provide a framework for the parties to work together through the project development phases.

In June 2023, Dr Kieran Mullan MP released a geothermal report for the UK Government recommending long term financial incentives for the industry.  His recommendations were endorsed by both the Prime Minister, Rishi Sunak, and the Secretary of State for Energy, Grant Shapps MP.  His report can be found here: https://lnkd.in/eqMqQtQU. 

Croatia

In August 2023, we announced our first overseas investment in geothermal, acquiring a 51% interest in A14 Energy that owns, via its Croatian subsidiary, IGeoPen d.o.o. (IGeoPen), the Ernestinovo exploration licence in the highly prospective Pannonian Basin.  The licence covers 76.7km² with a commitment to re-enter an existing well, by early April 2024. A conceptual programme for the Ernestinovo-3 workover well has been submitted and the work programme is on schedule to be completed as planned, satisfying the licence commitment.  The licence has excellent data from three deep exploration wells drilled nearby in the 1990s.

Based on preliminary heat reserves and well productivity estimates, the Company's internal assessment forecasts the potential for a first phase development of a 10MW electricity generation plant utilising five to six wells producing and re-injecting geothermal brine.

The proposed plant would connect into the Ernestinovo HOPS substation - a major substation with 400kV transmission lines to Zagreb, Hungary, Serbia and Bosnia, and local distribution lines at 110 kV and 85kV - and sell electricity on either a market premium arrangement (CfD) or bilaterally. 

There is upside potential for plant extension (an additional 5 to 10 MW) upon permit area extension (subject to tender) and potential for heat for green-houses and milk processing plants as the area is predominantly agricultural.

In addition to the Ernestinovo Licence, bids have been submitted, through IGeoPen, for three further highly prospective licence areas in the Drava depression geological region, located in the southwestern area of the Pannonian basin.  Licensing is through the Croatian Hydrocarbon Agency. An initial five-year exploration licence is granted, followed by the development licence (subject to fulfilling licence obligations during the exploration phase).

The Croatian Hydrocarbon Agency has communicated that it has received 16 offers from a total of 11 companies (including our bids) and the results of the round are expected by the end of 2023.

Interest in geothermal exploration and the development of geothermal projects in Croatia is growing fast, driven by government support and promotion of the sizable resource potential.  The Croatian Government is highly supportive and is actively promoting the sector internationally. The Croatian electricity market is liberalised and well established and it offers an attractive market premium (CfD) for a 12-year period.

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. In addition, 2D and 3D seismic surveys have been accessible, that cover c.20,000km², including the Ernestinovo licence and the three licence areas that the parties have applied for in the current licensing round.

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.

The acquisition brings a small team of highly regarded geothermal and geological experts with a recognised track record in the Croatian energy sector, with key personnel having led the development of Croatia's first geothermal power plant (Velika 1).

Financial review

Income Statement

The Group generated revenue of £23.8 million in the first six months of 2023 from sales of 361,549 barrels of oil, including sales of third party oil, 4,870 Mwh of electricity and 988,421 therms of gas (H1 2022: revenue £30.5 million, sales of 316,171 barrels of oil, 6,231 Mwh of electricity and 938,203 therms of gas).

Brent prices decreased compared to the first half of 2022 averaging $79.8/bbl in H1 2023 compared to $107.6/bbl during H1 2022.

Adjusted EBITDA for H1 2023 was £9.4 million (H1 2022: £10.7 million). The profit after tax from continuing activities was £0.5 million (H1 2022: £19.4 million) and the main factors explaining the movements between H1 2023 and H1 2022 were as follows:

·   Revenues of £23.8 million (H1 2022: £30.5 million) as strong production levels and a stronger US dollar were offset by the impact of lower prices. The Group benefited from its hedging policy with 60,000 bbls hedged in the period at an average of $95.0/bbl resulting in a realised gain of £0.7 million;

·   DD&A increased to £3.3 million (H1 2022: £2.7 million) as a result of higher production in the period;

·   Operating costs increased to £12.3 million (H1 2022: £10.8 million) mainly as a result of increased workover and maintenance activity carried out during the period as part of the Group's production drive. Higher transportation costs reflected the higher volumes. The Group also experienced inflationary increases in staff, materials and equipment costs;

·   Administrative expenses reduced to £2.6 million (H1 2022: £2.8 million) as we continue to focus on efficiencies to offset inflationary pressures;

·   Nil write-offs in exploration and evaluation assets (H1 2022: £6.5 million was written off in the first half of FY 2022 relating to PEDL 184 following the rejection of planning consent on appeal for a well test of the Ellesmere Port-1 well);

·   No impairment charge or reversal in the period (H1 2022: an impairment reversal of £10.5 million recognised on oil and gas assets as a result of the higher oil prices. An impairment charge of £1.5 million recorded in respect of past costs on our Lybster licence);

·   A realised gain was recognised on oil price derivatives of £0.7 million as 60,000 bbls were hedged at an average price of $95.0/bbl (H1 2022: loss of £5.8 million). In addition, there was an unrealised loss on hedges of £0.3 million (H1 2022: £1.7 million);

·   Net finance costs reduced to £1.9 million (H1 2022: £2.9 million). A reduction in amounts drawn under our RBL facility was partially offset by higher interest rates. Movements in the USD/GBP exchange rates resulted in a foreign exchange gain on our US$ denominated debt in the current period compared to a loss in the previous period. This was partially offset by an increase in the unwinding of discount on decommissioning provision as a result of an increase in the discount rates; and

·   A tax charge of £3.7 million was recognised in the period (H1 2022: tax credit of £13.2 million) relating to a current Energy Profits Levy charge of £0.9 million and a deferred tax charge of £2.7 million principally due to reduction in the amount of recognised tax losses due to lower forecast oil prices.

Cash Flow

Net cash generated from operations after realised hedge losses and before working capital movements was £9.2 million for the period (H1 2022: £10.6 million). The Group invested £4.4 million across its asset base during the period (H1 2022: £2.9 million). £3.7 million (H1 2022: £2.5 million) was invested in conventional assets, primarily on site preparation for our development project at Corringham and in smaller projects to generate near-term production. We also continued to offset field declines by upgrading facilities and systems and optimising production at a number of sites. £0.3 million (H1 2022: £0.3 million) was invested in working up additional exploration opportunities on conventional assets. We also invested £0.4 million (H1 2022: £0.1 million) in further developing our UK geothermal projects.

We repaid £3.3 million ($4.0 million) on borrowings under our RBL facility (H1 2022: £4.6 million ($6.0 million)) and paid £0.4 million ($0.5 million) in interest (H1 2022: £0.4 million ($0.5 million)). The impact of lower amounts drawn under the facility was offset by higher interest rates and a stronger US$. Repayment of obligations under operating leases was £0.8 million (H1 2022: £0.9 million).

Cash and cash equivalents were £1.5 million at the end of the period (31 December 2022: £3.1 million).

Balance Sheet

Net assets were £59.3 million at 30 June 2023 (31 December 2022: £58.3 million). Strong operating cash flows enabled a reduction in net debt by £2.1 million.  Trade and other payables reduced by £2.2 million mainly due to the timing of capital and abandonment expenditure. A reduction in the decommissioning provision due to wells being abandoned in the period and a reassessment of the timing of abandonments was partially offset by the unwinding of the discount. There was a reduction of £2.7 million in the deferred tax asset recognised at the end of the period following a reduction in forecast oil prices. We have also recognised a current tax charge of £0.9 million related to the Energy Profits Levy.

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, underlying cash operating costs and operating cash flow before working capital movements and realised hedges, which are considered by the Group to be useful additional measures to help understand underlying performance. These non-IFRS measures are used by the Directors for planning and reporting and should not be considered an IFRS replacement.

Net Debt

Net debt, being borrowings excluding capitalised fees less cash and cash equivalents, decreased to £4.0 million at 30 June 2023 (31 December 2022: £6.1 million; 30 June 2022: £9.7 million). The Group's definition of net debt does not include the Group's lease liabilities.

Adjusted EBITDA

Adjusted EBITDA includes adjustments in relation to non-cash items such as share-based payment charges and unrealised gain/loss on hedges along with other one-off exceptional items, and after deducting lease rentals capitalised under IFRS 16.

Underlying cash operating costs

* this represents total cost of sales less depletion, depreciation and amortisation.

Operating cash flow before working capital movements and realised hedges

Principal risks and uncertainties

The Group constantly monitors the Group's risk exposures and management reports to the Audit Committee and the Board on a regular basis.  The Audit Committee receives and reviews these reports and focuses on ensuring that the effective systems of internal financial and non-financial controls including the management of risk are maintained.  The results of this work are reported to the Board which in turn performs its own review and assessment.

The principal risks for the Group remain as previously detailed on pages 20-21 of the 2022 Annual Report and Accounts and can be summarised as:

·     Political risk such as change in Government or the effect of local or national referendums which can result in changes to the regulatory or fiscal regime;

·     Strategy, and its execution, fails to meet shareholder expectations;

·     Climate change risks that causes changes to laws, regulations, policies, obligations and social attitudes relating to the transition to a lower carbon economy which could have a cost impact or reduced demand for hydrocarbons for the Group and could impact our Strategy;

·     Cyber security risk that gives exposure to a serious cyber-attack which could affect the confidentiality of data, the availability of critical business information and cause disruption to our operations;

·     Planning, environmental, licensing and other permitting risks associated with its operations and, in particular, with drilling and production operations;

·     Oil or gas production, as no guarantee can be given that they can be produced in the anticipated quantities from any or all of the Group's assets or that oil or gas can be delivered economically;

·     Loss of key staff;

·     Pandemic that impacts the ability to operate the business effectively;

·     Oil market price risk through variations in the wholesale price in the context of the production from oil fields it owns and operates;

·     Gas and electricity market price risk through variations in the wholesale price in the context of its future unconventional production volumes;

·     Exchange rate risk through both its major source of revenue and its major borrowings being priced in US$ while most of the Group's operating and G&A costs are denominated in UK pounds sterling;

·     Liquidity risk through its operations; and

·     Capital risk resulting from its capital structure, including operating within the covenants of its RBL facility.

Going concern

The Group continues to closely monitor and manage its liquidity risks. Cash flow forecasts for the Group are regularly produced 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 under the RBL. Sensitivities are run to reflect different scenarios including, but not limited to, possible further reductions in commodity prices, strengthening of sterling and reductions in forecast oil production rates.

Crude oil prices saw a decline in H1 2023 compared to 2022. The higher prices prevailing during the first half of 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. Oil prices softened in the second half of 2022 and the first half of 2023. Prices have increased in H2 2023 but uncertainty remains with cost of living and recession concerns in many economies increasing risks on the demand side whereas OPEC supply reductions and geopolitical concerns are supporting prices.

The Group has generated strong operating cashflows in the first half of 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      on the Group not breaching its current RBL covenants.

The Group's base case cash flow forecast was run with average oil prices of $85/bbl for the remainder of 2023, falling to an average of $83/bbl in 2024 and $75/bbl in Q1 25 based on the forward curve, and a foreign exchange rate of an average $1.27/£1 for the 18-month period. We also assumed that our existing RBL facility is amortised in line with its terms, but is not refinanced or extended, resulting in a reduction in the facility to $nil million from 30 June 2024. Our forecasts show that the Group will have sufficient financial headroom to meet its financial covenants based on the existing RBL facility up to the date of its maturity in June 2024.

Management has also prepared a downside case with average oil prices of $75/bbl for Q4 2023; $73/bbl for H1 2024, falling to $68/bbl and $65/bbl for Q3 and Q4 2024, respectively, and $62/bbl for Q1 2025. We used an average exchange rate of $1.27/£1 for the remainder of 2023 and $1.30/£1 for 2024 and Q1 2025. Our downside case also included an average reduction in production of 5% over the period. In the event of the downside scenario, management would take mitigating actions including delaying capital expenditure and reducing costs, in order to remain within the Group's debt liquidity covenants over the remaining facility period, should such actions be necessary. All such mitigating actions are within management's control. We have not assumed any extensions or refinancing to the RBL. In this downside scenario, our forecast shows that the Group will have sufficient funds to meet the liabilities as they fall due over the going concern assessment period. The Group will also have adequate      financial headroom to meet its financial covenants based on the existing RBL facility up to the date of its maturity in June 2024. Management remains focused on maintaining a strong balance sheet and funding to support our strategy. As part of this financial policy, management continues to assess funding options for both the near and longer term     .

Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue in existence for the foreseeable future and have concluded it is appropriate to adopt the going concern basis of accounting in the preparation of the half year financial statements.

Statement of Directors' responsibilities

The Directors confirm that these Condensed Interim Consolidated Financial Statements have been prepared in accordance with UK-adopted International Accounting Standard 34, 'Interim Financial Reporting' ("IAS 34") and the AIM Rules for Companies; and these Unaudited Interim results include:

a)    a fair review of the information required (i.e., an indication of important events and their impact during the first six months and a description of the principal risks and uncertainties for the remaining six months of the financial year); and

b)    a fair review of the information required on related party transactions.

By order of the Board,

Chris Hopkinson

Chief Executive Officer

13 September 2023

Independent review report to Star Energy Group plc (formerly IGas Energy plc)

Report on the condensed interim consolidated financial statements

Our conclusion

We have reviewed Star Energy Group plc's (formerly IGas Energy plc) condensed interim consolidated  financial statements (the "interim financial statements") in the Unaudited Interim Results of Star Energy Group plc for the 6 month period ended 30 June 2023 (the "period").

Based on our review, nothing has come to our attention that causes us to believe that the interim financial statements are not prepared, in all material respects, in accordance with UK adopted International Accounting Standard 34, 'Interim Financial Reporting' and the AIM Rules for Companies.

The interim financial statements comprise:

·     the Condensed Interim Consolidated Balance Sheet as at 30 June 2023;

·     the Condensed Interim Consolidated Income Statement and Condensed Interim Consolidated Statement of Comprehensive Income for the period then ended;

·     the Condensed Interim Consolidated Cash Flow Statement for the period then ended;

·     the Condensed Interim Consolidated Statement of Changes in Equity for the period then ended; and

·     the explanatory notes to the interim financial statements.

The interim financial statements included in the Unaudited Interim Results of Star Energy Group plc have been prepared in accordance with UK adopted International Accounting Standard 34, 'Interim Financial Reporting' and the AIM Rules for Companies.

Basis for conclusion

We conducted our review in accordance with International Standard on Review Engagements (UK) 2410, 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Financial Reporting Council for use in the United Kingdom ("ISRE (UK) 2410"). A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures.

A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and, consequently, does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

We have read the other information contained in the Unaudited Interim Results and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim financial statements.

Conclusions relating to going concern

Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for conclusion section of this report, nothing has come to our attention to suggest that the Directors have inappropriately adopted the going concern basis of accounting or that the Directors have identified material uncertainties relating to going concern that are not appropriately disclosed. This conclusion is based on the review procedures performed in accordance with ISRE (UK) 2410. However, future events or conditions may cause the Group to cease to continue as a going concern.

Responsibilities for the interim financial statements and the review

Our responsibilities and those of the Directors

The Unaudited Interim Results, including the interim financial statements, is the responsibility of, and has been approved by the Directors. The Directors are responsible for preparing the Unaudited Interim Results in accordance with the AIM Rules for Companies which require that the financial information must be presented and prepared in a form consistent with that which will be adopted in the Company's annual financial statements. In preparing the Unaudited Interim Results, including the interim financial statements, the Directors are responsible for assessing the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the Directors either intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so.

Our responsibility is to express a conclusion on the interim financial statements in the Unaudited Interim Results based on our review. Our conclusion, including our Conclusions relating to going concern, is based on procedures that are less extensive than audit procedures, as described in the Basis for conclusion paragraph of this report. This report, including the conclusion, has been prepared for and only for the Company for the purpose of complying with the AIM Rules for Companies and for no other purpose. We do not, in giving this conclusion, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

PricewaterhouseCoopers LLP

Chartered Accountants

London

13 September 2023

Condensed Interim Consolidated Income Statement

Condensed Interim Consolidated Statement of Comprehensive Income

Condensed Interim Consolidated Balance Sheet

Condensed Interim Consolidated Statement of Changes in Equity

*           The foreign currency translation reserve represents 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 EIP/MRP/LTIP/VCP/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) 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) capital contribution reserve which arose following the acquisition of IGas Exploration UK Limited; and 4) merger reserve which arose on the reverse acquisition of Island Gas Limited.

Condensed Interim Consolidated Cash Flow Statement

Notes to the Unaudited Condensed Interim Consolidated Financial Statements

1    Corporate information

The condensed interim consolidated financial statements of Star Energy Group plc (formerly known as IGas Energy plc) and its subsidiaries (the Group) for the six months ended 30 June 2023, which are unaudited, were authorised for issue in accordance with a resolution of the Directors on 13 September 2023. Star Energy Group plc is a public limited company incorporated and domiciled in England whose shares are publicly traded on the AIM market. The Group's principal activities are exploring for, appraising, developing and producing oil and gas and developing geothermal projects.

2    Accounting policies

Basis of preparation

These unaudited condensed interim consolidated financial statements for the six months ended 30 June 2023 have been prepared in accordance with UK-adopted International Accounting Standard 34, 'Interim Financial Reporting' ("IAS 34") and the AIM Rules for Companies. The unaudited condensed interim consolidated financial statements should be read in conjunction with the consolidated financial statements for the year ended 31 December 2022. The annual financial statements of Star Energy Group plc are prepared in accordance with UK-adopted International Accounting Standards.

The financial information contained in this document does not constitute statutory accounts as defined by Section 434 of the Companies Act 2006 (England & Wales). The financial information as at 31 December 2022 is based on the statutory accounts for the year ended 31 December 2022.  A copy of the statutory accounts for that year, has been delivered to the Registrar of Companies and is available on the Company's website at www.starenergygroupplc.com. The auditors' report in accordance with Chapter 3 Part 16 of the Companies Act 2006 in relation to those accounts was unqualified, did not draw attention to any matters by way of emphasis and did not contain a statement under section 498(2) or (3) of the Companies Act 2006.

The accounting policies adopted are consistent with those of the previous financial year and corresponding interim reporting period, except for the adoption of the new and amended standards and interpretations discussed below.

Going concern

The Group continues to closely monitor and manage its liquidity risks. Cash flow forecasts for the Group are regularly produced 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 under the RBL. Sensitivities are run to reflect different scenarios including, but not limited to, possible further reductions in commodity prices, strengthening of sterling and reductions in forecast oil production rates.

Crude oil prices saw a decline in H1 2023 compared to 2022. The higher prices prevailing during the first half of 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. Oil prices softened in the second half of 2022 and the first half of 2023. Prices have increased in H2 2023 but uncertainty remains with cost of living and recession concerns in many economies increasing risks on the demand side whereas OPEC supply reductions and geopolitical concerns are supporting prices.

The Group has generated strong operating cashflows in the first half of 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      on the Group not breaching its current RBL covenants.

The Group's base case cash flow forecast was run with average oil prices of $85/bbl for the remainder of 2023, falling to an average of $83/bbl in 2024 and $75/bbl in Q1 25 based on the forward curve, and a foreign exchange rate of an average $1.27/£1 for the 18-month period. We also assumed that our existing RBL facility is amortised in line with its terms, but is not refinanced or extended, resulting in a reduction in the facility to $nil million from 30 June 2024. Our forecasts show that the Group will have sufficient financial headroom to meet its financial covenants based on the existing RBL facility up to the date of its maturity in June 2024.

Management has also prepared a downside case with average oil prices of $75/bbl for Q4 2023; $73/bbl for H1 2024, falling to $68/bbl and $65/bbl for Q3 and Q4 2024, respectively, and $62/bbl for Q1 2025. We used an average exchange rate of $1.27/£1 for the remainder of 2023 and $1.30/£1 for 2024 and Q1 2025. Our downside case also included an average reduction in production of 5% over the period. In the event of the downside scenario, management would take mitigating actions including delaying capital expenditure and reducing costs, in order to remain within the Group's debt liquidity covenants over the remaining facility period, should such actions be necessary. All such mitigating actions are within management's control. We have not assumed any extensions or refinancing to the RBL. In this downside scenario, our forecast shows that the Group will have sufficient funds to meet the liabilities as they fall due over the going concern assessment period. The Group will also have adequate      financial headroom to meet its financial covenants based on the existing RBL facility up to the date of its maturity in June 2024. Management remains focused on maintaining a strong balance sheet and funding to support our strategy. As part of this financial policy, management continues to assess funding options for both the near and longer term     .

Based on the analysis above, the Directors have a reasonable expectation that the Group has adequate resources to continue in existence for the foreseeable future and have concluded it is appropriate to adopt the going concern basis of accounting in the preparation of the half year financial statements.

2    Accounting policies (continued)

New and amended standards and interpretations

During the period, the Group adopted the following new and amended IFRSs for the first time for their reporting period commencing 1 January 2023:

These standards do not have a material impact on the Group in the current or future reporting periods. There are no other standards that are not yet effective and that would be expected to have a material impact on the entity in the current or future reporting periods.

Estimates and judgements

The preparation of the unaudited condensed interim consolidated financial statements requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates.

In preparing these unaudited condensed interim consolidated financial statements, the significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those applied to the consolidated financial statements for the year ended 31 December 2022.

Financial risk management

The Group's activities expose it to a variety of financial risks; market risk (including interest rate, commodity price and foreign currency risks), credit risk and liquidity risk.

The unaudited condensed interim consolidated financial statements do not include financial risk management information and disclosures required in the annual financial statements; accordingly, the unaudited condensed interim consolidated financial statements should be read in conjunction with the Group's annual financial statements as at 31 December 2022.

3     Basis of consolidation

The unaudited condensed interim consolidated financial statements present the results of Star Energy Group plc and its subsidiaries as if they formed a single entity. The financial information of subsidiaries used in the preparation of these unaudited condensed interim consolidated financial statements is based on consistent accounting policies to those of the Company. All intercompany transactions and balances between Group companies, including unrealised profits/losses arising from them, are eliminated in full. Where shares are issued to an Employee Benefit Trust, and the Company is the sponsoring entity, it is treated as an extension of the entity.

 4     Revenue

The Group derives revenue solely within the United Kingdom from the transfer of control over goods and services to external customers which is recognised at a point in time when the performance obligation has been satisfied by the transfer of goods.  The Group's major product lines are:

5      Finance income and costs

6     Tax on profit on ordinary activities

The Group calculates the period income tax expense using the UK corporation tax rate that would be applicable to expected total annual earnings for the 12 months ended 31 December 2023. The majority of the Group's profits are generated by "ring-fence" business which attract UK corporation tax and supplementary charges at a combined average rate of 40% (six months ended 30 June 2022: 40%), in addition to the Energy Profit Levy introduced in May 2022 with an expected average rate of 35% for the period (six months ended 30 June 2022: 0%). The effective tax rate for the period is 87% (six months ended 30 June 2022: -212%), reflecting the deferred tax charge of £2.7 million in the period, primarily as a result of the reduction in the value of recognised tax losses as oil prices softened in 2023 following a spike in 2022, and a current tax charge of £0.9 million under the Energy Profit Levy regime. The major components of income tax expense in the unaudited condensed interim consolidated income statement are:

A deferred tax asset of £42.1 million (30 June 2022: £51.4 million, 31 December 2022: £44.8 million) has been recognised in respect of tax losses and other temporary differences where the Directors believe that it is probable that these assets will be recovered based on estimated taxable profit forecast.

The Group has gross total tax losses and similar attributes carried forward of £350.8 million (30 June 2022: £353.1 million, 31 December 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 are offsetting deferred tax liabilities. Such recognised tax losses include £117.7 million (30 June 2022: £130.7 million, 31 December 2022: £123.2 million) of ringfence corporation tax losses which will be recovered at 30% of future taxable profits, £115.9 million (30 June 2022: £123.8 million, 31 December 2022: £119.8 million) of supplementary charge tax losses which will be recovered at 10% of future taxable profits and £nil (30 June 2022: £nil, 31 December 2022: £1.9 million) of losses arising under the EPL regime which will be recovered at 35% of future taxable profits.

7      Loss after tax from discontinued operations

The divestment of assets acquired as part of the Dart Acquisition, namely the Rest of the World segment, was completed in 2016.  The Group had a presence in a small number of Australian, Indian and Singaporean registered operations. During the year ended 31 December 2022, we substantially finalised the liquidation process for the remaining of these overseas dormant subsidiaries, with formal deregistration of the final Australian entity (Dart Energy Pty Ltd) expected to be confirmed in the second half of 2023. The total loss after tax in respect of discontinued operations was £nil (six months ended 30 June 2022: £nil; year ended 31 December 2022: £nil).

8     Earnings per share (EPS)

Basic EPS amounts are based on the profit from continuing operations for the period after taxation attributable to ordinary equity holders of the parent of £0.5 million (six months ended 30 June 2022: a profit after tax of £19.4 million; year ended 31 December 2022: a loss after tax of £11.8 million) and the weighted average number of ordinary shares outstanding during the period of 127.2 million (six months ended 30 June 2022: 125.7 million; year ended 31 December 2022: 125.9 million).

Diluted EPS amounts are based on the profit/ (loss) for the period/ year after taxation attributable to the ordinary equity holders of the parent and the weighted average number of shares outstanding during the period/ year plus the weighted average number of ordinary shares that would be issued on the conversion of all the potentially dilutive ordinary shares into ordinary shares, except where these are anti-dilutive.

As at 30 June 2023, there are 9.1 million potentially dilutive employee share options (six months ended 30 June 2022: 9.8 million, year ended 31 December 2022: 11.9 million). These are included in the calculation of diluted earnings per share in the current period and as at 30 June 2022. These were not included in the calculation at 31 December 2022 as their conversion to ordinary shares would have decreased the loss per share.

9     Intangible assets

Exploration and evaluation assets

Exploration costs written off in the period to 30 June 2023 were £nil (6 months to 30 June 2022: £6.5 million, year ended 31 December 2022: £30.0 million). The 2022 exploration costs written off related to unconventional assets where the Board concluded it was unlikely that the Group would be able to proceed with 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 (six months ended 30 June 2022: £5.2 million, year ended 31 December 2022: £5.6 million) of capitalised exploration expenditure which relates to our conventional assets including PEDL 235 and PL 240. Our unconventional assets have been fully impaired.

Management has assessed the 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.

Development costs

The development costs relate to assets acquired as part of the GT Energy acquisition in 2020. 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 30 June 2023 and assessed it for impairment indicators. The development of the Stoke-on-Trent project has taken longer than anticipated initially due to COVID-19 and more recently on account of delays on receiving formal approval of the grant under the UK Government's Green Heat Network Fund. We applied for the grant funding for the Stoke-on-Trent project jointly with SSE and we are hoping to hear the outcome in the second half of the year. The delayed timing does not adversely impact the overall economics of the project materially and a successful outcome on our grant application to the GHNF will significantly de-risk the project. On this basis, the Group has concluded that there are no impairment indicators as at 30 June 2023 and no impairment was required for the period (year ended 31 December 2022: £nil).

10   Property, plant and equipment

Impairment of oil and gas properties

The Group reviewed the carrying value of oil and gas assets as at 30 June 2023 and assessed it for impairment and impairment reversal indicators. No factors that would have a material impact on the carrying value of the assets since the last balance sheet date were identified. Management has therefore concluded that there were no impairment or impairment reversal indicators at 30 June 2023. 

11     Financial Instruments - fair value disclosure

The Group uses the following hierarchy for determining and disclosing the fair value of financial instruments by valuation technique:

●      Level 1: quoted (unadjusted) prices in active markets for identical assets or liabilities;

●      Level 2: other valuation techniques for which all inputs which have a significant effect on the recorded fair value are observable, either directly or indirectly; and

●      Level 3: valuation techniques which use inputs which have a significant effect on the recorded fair value that are not based on observable market data.

There are no non-recurring fair value measurements nor have there been any transfers between levels of the fair value hierarchy.

Financial assets and liabilities measured at fair value

Fair value of derivative financial instruments

Commodity price hedges

The fair values of the commodity price hedges were provided by counterparties with whom the trades have been entered into. These consist of Asian style put and call options and swaps to sell/buy oil.  The hedges are valued using a Black-Scholes methodology; however, certain adjustments are made to the spot-price volatility of oil prices due to the nature of the contracts. These adjustments are made either through Monte Carlo simulations or through statistical formulae.  The inputs to these valuations include the price of oil, its volatility, and risk free interest rates.

Fair value of other financial assets and financial liabilities

The fair values of all other financial assets and financial liabilities are considered to be materially equivalent to their carrying values.

12    Provisions

Decommissioning provision

The Group spent £1.6 million on decommissioning activities during the period (six months ended 30 June 2022: £0.6 million; year ended 31 December 2022: £2.3 million).

Provision has been made for the discounted future cost of abandoning wells and restoring sites to a condition acceptable to the relevant authorities. This is expected to take place between 1 to 29 years from period end (30 June 2022: 1 to 39 years; 31 December 2022: 1 to 30 years). The provisions are based on the Group's internal estimate as at 30 June 2023. Assumptions are based on the current 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 2023-2025 on preparing for the abandonment campaign, abandoning wells and restoring sites which for regulatory, integrity or other reasons fall outside the planned campaign. The wells to be decommissioned in 2023 and 2024 are in line with management's discussions with the regulator. 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 - 2024 and thereafter incorporates the long-term UK target inflation rate for the period 2025 and beyond.

A risk free rate range of 3.0% to 5.9% is used in the calculation of the provision as at 30 June 2023 (30 June 2022: Risk free rate range of 2.3% to 3.0%, 31 December 2022: Risk free rate range of 3.0% to 5.1%).

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 £3.4 million whereas a 1% increase in inflation applied until the end of 2025 would result in an increase in the decommissioning provision by £1.8 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 carrying value of contingent consideration relates to the acquisition of GT Energy. The consideration is payable in shares, and is dependent on the timing of various milestones being achieved. It is also dependent on the inputs to an agreed-form economic model which determines the level of the consideration for each milestone in accordance with the 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.

13    Cash and cash equivalents and other financial assets

Net debt reconciliation

Reserve 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 had 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 has 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 30 June 2023, we had an available facility limit of $12 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. 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 Net Debt at the period end to 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 six months ended 30 June 2023.

13    Cash and cash equivalents and other financial assets (continued)

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 (formerly Star Energy Group 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 have 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).

14     Share capital

15     Subsequent events

On 29 August 2023, Star Energy announced the acquisition of 51% of the issued share capital of A14 Energy Limited ("A14 Energy"). A14 Energy owns, via its Croatian subsidiary, IGeoPen d.o.o., the Ernestinovo geothermal waters exploration licence in the highly prospective Pannonian Basin in Croatia. 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 purchase was for a total cash consideration of €1.3 million (£1.1 million), in addition to the payment of €0.1 million (£0.1 million) relating to the provision of cash backed guarantees to the Croatian Hydrocarbon Agency and €0.2 million (£0.2 million) in back costs relating to the ongoing appraisal of the Ernestinovo licence. The accounting for this transaction is in progress at the date of approval of these unaudited condensed interim consolidated financial statements, in light of the fact that the transaction has only closed very recently.

Glossary

£ The lawful currency of the United Kingdom

$ The lawful currency of the United States of America

1P Low estimate of commercially recoverable reserves

2P Best estimate of commercially recoverable reserves

3P High estimate of commercially recoverable reserves

1C Low estimate or low case of Contingent Recoverable Resource quantity

2C Best estimate or mid case of Contingent Recoverable Resource quantity

3C High estimate or high case of Contingent Recoverable Resource quantity

AIM AIM market of the London Stock Exchange

Bbl(s)/d  Barrel(s) of oil per day

boepd Barrels of oil equivalent per day

bopd Barrels of oil per day

CCUS Carbon capture usage and storage

Contingent Recoverable Resource - Contingent Recoverable Resource estimates are prepared in accordance with the Petroleum Resources Management System (PRMS), an industry recognised standard. A Contingent Recoverable Resource is defined as discovered potentially recoverable quantities of hydrocarbons where there is no current certainty that it will be commercially viable to produce any portion of the contingent resources evaluated. Contingent Recoverable Resources are further divided into three status groups: marginal, sub‑marginal, and undetermined. Star Energy Group plc's Contingent Recoverable Resources all fall into the undetermined group. Undetermined is the status group where it is considered premature to clearly define the ultimate chance of commerciality.

Drill or drop - A drill or drop well carries no commitment to drill. The decision whether or not to drill the well rests entirely with the Licensee being driven by the results of geotechnical analysis. The Licence will, however, still expire at the end of the Initial Term if the well has not been drilled.

Firm well - A firm well is classified as a firm commitment to drill a well. It is not contingent on any further geotechnical evaluation (i.e. it is a fully evaluated Prospect).

GIIP Gas initially in place

m Million

Mbbl Thousands of barrels

MMboe Millions of barrels of oil equivalent

MMscfd Millions of standard cubic feet per day

PEDL United Kingdom petroleum exploration and development licence

PL Production licence

Tcf Trillions of standard cubic feet of gas

UK United Kingdom